Exall Energy Corporation
TSX : EE
TSX : EE.DB

Exall Energy Corporation

March 19, 2015 08:00 ET

Exall Energy Corporation Announces Results for the Three Months and Year Ended December 31, 2014

CALGARY, ALBERTA--(Marketwired - March 19, 2015) - Exall Energy Corporation ("Exall" or the "Company") (TSX:EE)(TSX:EE.DB) is pleased to announce its financial and operating results for the three months and fiscal year ended December 31, 2014, and that it has filed its Annual Information Form which contains reserves data and other oil and gas information required by Section 2.1 of NI 51-101. Exall's annual filings can all be found at www.exall.com or www.sedar.com.


HIGHLIGHTS
3 months ended December 31 Year ended December 31
In thousands of dollars 2014 2013 %
change
2014 2013 %
change
Financial ($)
Gross revenue 2,936 7,307 (60 ) 23,318 36,262 (36 )
Funds from operations (210 ) 1,521 2,353 12,896 (210 ) 1,521
Basic per share (0.00 ) 0.02 0.04 0.19 (0.00 ) 0.02
Diluted per share (0.00 ) 0.02 0.04 0.19 (0.00 ) 0.02
Net income (loss) (54,055 ) (17,301 ) (62,633 ) (16,428 ) (54,055 ) (17,301 )
Basic per share (0.81 ) (0.26 ) (0.94 ) (0.25 ) (0.81 ) (0.26 )
Diluted per share (0.81 ) (0.26 ) (0.94 ) (0.25 ) (0.81 ) (0.26 )
Capital expenditures, net 1,084 4,055 (73 ) 3,759 12,154 (69 )
Operations
Daily production
Crude oil (bbl) 420 908 (54 ) 649 1,059 (39 )
Natural gas liquids (bbl) 8 17 (53 ) 23 18 28
Natural gas (mmcf) 75 319 (76 ) 207 368 (44 )
Total daily production (boe @ 6:1) 440 978 (55 ) 706 1,138 (38 )
Netback per boe (6:1) ($) 21.55 38.07 (43 ) 40.03 47.21 (15 )

Results of Operations

Oil and gas exploration and development expenditures were $961 for the three month period ended December 31, 2014. During the fourth quarter of 2014 the Company participated in the drilling of 0.0 gross oil wells (0.00 net) in the Marten Mountain / Mitsue area. During the fourth quarter of 2013 the Company participated in the drilling of 0.0 gross oil wells (0.00 net) in the Marten Mountain / Mitsue area.

As at December 31, 2014, the Company had 182,250 acres (139,433 acres net) of undeveloped land in Alberta, Canada.

Production for 2014 of 706 boe per day represents a 38% decrease over 2013. Funds from operations for the year of $2.4 million or $0.04 per share were primarily the result of the 38% decrease in production, a 4% increase in commodity prices received during the year averaging $90.49 per boe compared to $87.27 per boe in 2013, a 19% increase in royalty prices paid during the year averaging $33.55 per boe compared to $28.24 per boe in 2013, and a 43% increase in operating costs paid during the year averaging $16.91 per boe compared to $11.82 per boe in 2013.

Three months ended
December 31
Year ended
December 31

Netback per boe (6:1) $

2014

2013
%
Change

2014

2013
%
Change
Production revenue 72.47 81.21 (11 ) 90.49 87.27 4
Royalties 26.31 29.30 (10 ) 33.55 28.24 19
Operating expenses 24.61 13.84 78 16.91 11.82 43
Operating netbacks ($/boe) 21.55 38.07 (43 ) 40.03 47.21 (15 )

Production

Exall's average daily production for the three month period ended December 31, 2014 decreased 55 percent to 440 barrels of oil per day ("boe/d") from the 978 boe/d recorded in the same period of 2013.

Production by Region

Q1 2013Q2 2013Q3 2013Q4 2013Q1 2014Q2 2014Q3 2014Q4 2014
Mitsue Waterflood - Totals
Oilbbls/d1,2161,0821,028907884707585418
Natural Gasmmcf/d39434341731931825318775
Liquidsbbls/d192017172321398
Boe/d1,3011,1601,114977960770655439
Bow Island Heavy Oil
Oilbbls/d22212222
Natural Gasmmcf/d--------
Liquidsbbls/d--------
Boe/d22212222
Corporate Totals
Oilbbls/d1,2181,0841,030908886709587420
Natural Gasmmcf/d39434341731931825318775
Liquidsbbls/d192017172321398
Boe/d1,3031,1611,116978962772657440

During the fourth quarter of 2014 production was negatively affected by the lack of capital being reinvested and by the previously announced metering error. The metering error resulted in Exall injecting approximately 16 percent of the water the Company though it was injecting resulting in significant pressure depletion in the north part of the Mitsue Waterflood. The metering error was corrected in June 2014 and Exall has been over injecting during the fourth quarter with pressures starting to build and production levels starting to increase to levels the Company was initially expecting from the Mitsue North Waterflood.

Outlook

While Exall continues to seek debt restructuring alternatives, and will maintain this focus until completed, the Capital Expenditure Program for 2015 has been deferred until this effort is completed, subject to available funds.

Once resumed the Capital Expenditure Program is slated to continue to explore and develop the North Waterflood Gilwood channel extension of the Central Waterflood channel. Successful drilling on the Central Waterflood / North Waterflood channel extension through the last quarter of 2015 is expected to add 673 boepd net (based on an average working interest of 71.5 percent).

Capital expenditures through 2015 will continue to focus on the "low-hanging fruit" (LHF) opportunities. Short term focus of capital will be on well optimization and stimulation, waterflood implementation, and drilling of the lowest-risk, lowest-cost infill wells in the North Waterflood area. One water injection well conversion was completed and put into service in the fourth quarter of 2014. One additional water injector conversion is planned as one of the first LHF projects in 2015. A recently completed successful well stimulation has confirmed that well optimizations can improve production significantly in ageing horizontal and slant-hole wells. Exall plans to drill up to 8 gross development wells and 1 gross exploration well in 2015, subject to cash flow from operations. These wells are all high-impact, low risk locations identified through previous drilling and could have a significant impact on the Company's production if successful. Continued drilling success on the North Waterflood channel extension will drive production growth on an annual basis through 2015 and 2016.

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. The Company's oil price received averaged approximately $1.65 less than the posted Edmonton Par price at the wellhead through 2014. Based on the $1.65 differential, Exall expects that its 2015 average price received will be $59.88 per barrel. This pricing estimate is approximately $15.00 higher than the Western Canadian Select price expected by other entities during these periods.

Exall's current debt level is approximately $59.0 million which includes $26.0 million of revolving demand credit held under a facility with its current senior Canadian lender that bears interest at the lender's base prime rate plus 3.00 percent, $10.0 million of revolving demand credit held under a facility with its current senior Canadian lender that bears interest at the lender's base prime rate plus 3.00 percent, which are reviewed periodically by the lender. The balance of the debt is a $23.0 million Convertible Debenture with a maturity date of March 2017 that pays an annual interest rate of 7.75 percent.

As at December 31, 2014, the Company had a working capital deficit, excluding bank indebtedness, of $3.2 million ($38.0 million including bank indebtedness) and a shareholders' deficit of $24.9 million. The Company was not in compliance with the working capital covenant at December 31, 2014 and 2013 and the violation has not been waived by the lender. The credit facility technically expired on April 30, 2013 and the lender has informed the Company that it is demanding the loan. Exall announced, on November 04, 2014, that it had entered into a forbearance agreement ("Forbearance Agreement") with its current senior Canadian lender. The Forbearance Agreement allowed for a monitor to report on, amongst other information, the progress relating to the refinancing under a monitoring agreement ("Monitoring Agreement"), and the initiation of a formal sales process in relation to the Company and its assets. On taking these steps, and provided Exall met all its obligations under the Forbearance Agreement and the Monitoring Agreement, Exall's senior Canadian lender agreed to a forbearance period that could extend until up to February 13, 2015. The Forbearance Agreement technically expired on February 13, 2015; however, the lender has not yet taken formal action to demand repayment of the loan.

Exall announced on March 9, 2015 that further to its February 9, 2015 and February 11, 2015 announcements, Viking Investments Group, Inc. ("Viking") had advised Exall that given the current timing, it was considering dispensing with a bridge financing arrangement as a means to retire Exall's existing facility with its current senior Canadian lender (the "Facility") in full, and instead will utilize proceeds from a larger, long-term debt financing being contemplated by Viking in Mauritius with assistance from BAO Capital Sarl (the "Bond Transaction"). Approximately $35.0 million from the Bond Transaction would be used to pay the Facility in full, in consideration for an assignment of the Facility and security package. Viking has advised Exall it expects the Bond Transaction will close by the end of March, 2015. While the Company is hopeful that the alternative debt financing will close by the end of March 2015, there is no guarantee it will do so.

As at March 17, 2015, the Company was in continuous discussions with the lender and other potential lenders in regards to ongoing debt financing and is considering asset dispositions and other strategic alternatives to help the Company advance its overall business plan. The Company will continue to adjust the scope of its development plans and anticipated expenditures in light of its working capital position.

Reserves Evaluation

Exall retained Deloitte Petroleum Consultants ("Deloitte") to conduct an independent evaluation of Exall's oil and gas reserves effective December 31, 2014, which was provided to Exall in an Evaluation Report dated February 3, 2015 (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, 2014. 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.

Light & Natural
Company Gross Reserves(1) medium oil gas NGL Total
as at December 31, 2014 (Mbbl) (MMcf) (Mbbl) (Mboe)
Proved developed producing 628.3 207.5 19.5 682.4
Proved developed non-producing 156.4 47.5 4.5 168.8
Proved undeveloped 447.5 235.8 22.2 508.9
Total proved 1,232.2 490.8 46.1 1,360.1
Probable 954.5 471.0 44.3 1,077.3
Total proved plus probable 2,186.7 961.8 90.4 2,437.4
(1) Columns and rows may not add due to rounding
Before Income Tax
Forecast Net Revenue(1) $000s, discounted at
as at December 31, 2014 0% 5% 10% 15%
Proved developed producing 19,482.9 17,600.1 16,104.1 14,863.9
Proved developed non-producing 3,872.8 3,429.3 3,066.9 2,765.5
Proved undeveloped 11,012.3 9,235.0 7,791.2 6,601.4
Total proved 34,314.0 30,264.4 26,962.2 24,231.8
Probable 26,831.9 21,167.5 16,958.2 13,747.5
Total proved plus probable 61,145.9 51,431.9 43,920.4 37,979.3
(1) Columns and rows may not add due to rounding
After Income Tax
Forecast Net Revenue(1) $000s, discounted at
as at December 31, 2014 0% 5% 10% 15%
Proved developed producing 19,428.9 17,600.1 16,104.1 14,863.9
Proved developed non-producing 3,872.8 3,429.3 3,066.9 2,766.5
Proved undeveloped 11,012.3 9,235.0 7,791.2 6,601.4
Total proved 34,314.0 30,264.4 26,962.2 24,231.8
Probable 26,831.9 21,167.6 16,958.2 13,747.5
Total proved plus probable 61,145.9 51,431.9 43,920.4 37,979.3
(1) Columns and rows may not add due to rounding

The net changes to the Company's reserves and net present value are the function of both pricing and assignable reserves using NI 51-101 guidelines, in which Deloitte used 11 months of actual production data.

With regard to the Total Proved Reserves, Exall's 56 percent decline in the 10 percent net present value (before tax) is the result of; 1) the 31 percent decline in unit value per boe from the negative adjustments to future commodity pricing resulting in 55 percent of the total decline, 2) the 257,687 barrels actually produced by Exall and not replaced during Fiscal 2014, which represents 15 percent of the total decline, and 3) a 528,723 barrel net technical revision (including extensions & improved recoveries) assigned by Deloitte, primarily as a result of the conversion of one well from a producing well to a water injection well to support the Marten Mountain waterflood projects.

With regard to the Total Proved + Probable Reserves, Exall's 52 percent decline in the 10 percent net present value (before tax) is the result of; 1) the 29 percent decline in unit value per boe from the negative adjustments to future commodity pricing resulting in 57 percent of the total decline, 2) the 257,687 barrels actually produced by Exall and not replaced during Fiscal 2014, which represents 10 percent of the total decline, and 3) a 878,930 barrel net technical revision (including extensions & improved recoveries) assigned by Deloitte, primarily as a result of the conversion of one well from a producing well to a water injection well to support the Marten Mountain waterflood projects.

Summary of Forecast Pricing

Future prices used in the forecast of net revenue are based on those estimated by Deloitte as at December 31, 2014. 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
(%)
2015 $67.00 $70.95 $3.85 $28.40 $46.10 $70.95 0.86 0.0 0.0
2016 $71.40 $77.10 $4.15 $30.85 $50.15 $77.10 0.86 2.0 2.0
2017 $74.90 $82.25 $4.45 $32.90 $53.50 $82.25 0.86 2.0 2.0
2018 $78.55 $87.60 $4.80 $35.00 $56.95 $87.60 0.86 2.0 2.0
2019 $82.25 $93.15 $5.05 $37.25 $60.55 $93.015 0.86 2.0 2.0
2020 $86.10 $97.55 $5.35 $39.05 $63.45 $97.55 0.86 2.0 2.0
2021 $90.10 $102.15 $5.65 $40.90 $66.40 $102.15 0.86 2.0 2.0
2022 $91.90 $104.20 $5.85 $41.70 $67.70 $104.20 0.86 2.0 2.0
2023 $93.75 $106.25 $6.20 $42.55 $69.05 $106.25 0.86 2.0 2.0
2024 $95.60 $108.40 $6.40 $43.40 $70.45 $108.40 0.86 2.0 2.0
2025 $97.50 $110.55 $6.60 $44.25 $71.85 $110.55 0.86 2.0 2.0
2026 $99.45 $112.75 $6.85 $45.15 $73.30 $112.75 0.86 2.0 2.0
2027 $101.45 $115.05 $7.15 $46.05 $74.75 $115.05 0.86 2.0 2.0
2028 $103.50 $117.35 $7.30 $46.95 $76.25 $117.35 0.86 2.0 2.0
2029 $105.55 $119.70 $7.45 $47.90 $77.80 $119.70 0.86 2.0 2.0
2030 $107.65 $122.05 $7.60 $48.85 $79.35 $122.05 0.86 2.0 2.0
2031 $109.80 $124.50 $7.75 $49.85 $80.95 $124.50 0.86 2.0 2.0
2032 $112.00 $127.00 $7.90 $50.85 $82.55 $127.00 0.86 2.0 2.0
2033 $114.25 $129.55 $8.05 $51.85 $84.20 $129.55 0.86 2.0 2.0
2034 $116.55 $132.15 $8.25 $52.90 $85.90 $132.15 0.86 2.0 2.0
2035 + 2.0%
Escalated
2.0%
Escalated
2.0%
Escalated
2.0%
Escalated
2.0%
Escalated
2.0%
Escalated
0.86 2.0 2.0

Reserve Reconciliation

Light & Natural
Reserve Reconciliation(1) medium oil gas NGL Total
(Company Working Interest) (Mstb) (MMcf) (Mstb) (Mboe)
Proved
December 31, 2013 1,890.9 1,188.6 57.5 2,146.6
Extensions & improved recovery 125.9 41.4 3.9 136.7
Technical revisions (552.2 ) (659.2 ) (8.3 ) (670.4 )
Economic Factors (1.2 ) (0.2 ) 0.0 (1.2 )
Acquisitions 0.0 0.0 0.0 0.0
Dispositions 0.0 0.0 0.0 0.0
Production (231.2 ) (79.7 ) (7.0 ) (251.5 )
December 31, 2014 1,232.2 490.8 46.1 1,360.1
Probable
December 31, 2013 1,232.3 907.3 43.9 1,427.4
Extensions & improved recovery 13.4 2.7 0.3 14.1
Technical revisions (294.4 ) (439.6 ) 0.0 (367.7 )
Economic Factors 3.2 0.6 0.1 3.4
Acquisitions 0.0 0.0 0.0 0.0
Dispositions 0.0 0.0 0.0 0.0
Production 0.0 0.0 0.0 0.0
December 31, 2014 954.5 471.0 44.3 1,077.3
Proved plus Probable
December 31, 2013 3,123.2 2,095.9 101.4 3,574.0
Extensions & improved recovery 139.3 44.1 4.1 150.8
Technical revisions (846.6 ) (1,098.8 ) (8.3 ) (1,038.0 )
Economic Factors 2.0 0.4 0.1 2.2
Acquisitions 0.0 0.0 0.0 0.0
Dispositions 0.0 0.0 0.0 0.0
Production (231.2 ) (79.7 ) (7.0 ) (251.5 )
December 31, 2014 2,186.7 961.8 90.4 2,437.4
(1) Columns and rows may not add due to rounding

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.

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