Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) announces its
operating and financial results for the first quarter ended March 31, 2014.
HIGHLIGHTS
-- The average initial production rate over the first 30 days for the seven
Cardium horizontal light oil wells drilled in the winter program was 459
BOED per well.
-- Production in the first quarter of 2014 was 2,958 BOED of which 39% was
oil and NGL compared to 2,112 BOED (26% oil and NGL) for the fourth
quarter of 2013 (net of properties sold in the fourth quarter of 2013).
-- Funds from operations were $5.5 million in the first quarter of 2014
compared to negative funds from operations of $0.3 million in the fourth
quarter of 2013.
-- The operating netback was $34.51 per BOE in the first quarter of 2014
compared to $12.35 per BOE in the fourth quarter of 2013 (adjusted for
properties sold in the quarter).
-- The Board of Directors has approved a 2014 capital budget of $46
million. Annual production for 2014 is estimated to average
approximately 3,200 BOED (36% oil and NGL). Exit production for 2014 is
estimated to be approximately 3,700 BOED (42% oil and NGL). In addition
to the seven wells drilled this winter, the Company is planning to drill
15 gross (12.6 net) Cardium and Mannville light oil horizontal wells
from the second quarter of 2014 to spring breakup 2015.
-- GLJ Petroleum Consultants ("GLJ") have completed an interim reserves
report of all of the Company's oil and natural gas properties effective
April 30, 2014. This report includes the impact of the winter drilling
program, a positive change in the GLJ price deck and is net of
production to April 30, 2014. Proved developed producing ("PDP"), total
proved ("TP") and total proved plus probable("P&P") BOE reserves were
11%, 3% and 9% higher than reported at year end 2013.
-- At April 30, 2014, the Company had 3,811 MBOE PDP reserves (33% oil and
NGL), 5,472 MBOE TP reserves (36% oil and NGL) and 9,583 MBOE P&P
reserves (43% oil and NGL).
-- Anderson's total P&P pre-tax 10% net present value ("NPV 10") of
reserves at April 30, 2014 was $132.8 million, a 32% increase over the
reported December 31, 2013 value. Undeveloped land was valued at $3.4
million at December 31, 2013.
-- Cardium P&P reserves were 6.1 MMBOE representing 63% of total P&P
reserves volumes and 82% of total P&P NPV 10 reserves value.
-- The Company has agreed to an increase its bank facility from $28 million
to $ 31 million, subject to customary closing conditions. As of today's
date, the Company is not drawn on its bank facility.
-- 115 gross (73.3 net) light oil horizontal drilling locations have been
identified in the Cardium and Mannville zones. Only 31% of the net
locations are recognized as P&P locations in the interim reserves
report. Approximately 97% of the net locations are Company operated.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended
March 31
----------------------------------------------------------------------------
(thousands of dollars, unless otherwise %
stated) 2014 2013 Change
----------------------------------------------------------------------------
Oil and gas sales (1) $ 14,522 $ 16,863 (14%)
Revenue, net of royalties (1) $ 13,195 $ 15,268 (14%)
Funds from operations (2) $ 5,538 $ 5,486 1%
Funds from operations per share
Basic and diluted (2) $ 0.03 $ 0.03 -
Adjusted earnings (loss) before taxes (3) $ 544 $ (5,113) 111%
Adjusted earnings (loss) before taxes
per share - basic and diluted(3) $ - $ (0.03) 100%
Earnings (loss) $ 544 $ (5,113) 111%
Earnings (loss) per share
Basic and diluted $ - $ (0.03) 100%
Capital expenditures (net of proceeds on
dispositions) $ 16,032 $ 7,662 109%
Bank loans and other working capital
(deficiency) (2) $ (993) $ (66,783) 99%
Convertible debentures $ 89,517 $ 87,277 3%
Shareholders' equity $ 28,840 $ 128,110 (77%)
Average shares outstanding (thousands):
Basic 172,550 172,550 -
Diluted 172,943 172,550 -
Ending shares outstanding (thousands) 172,550 172,550 -
Average daily sales volumes:
Oil (bpd) 969 1,529 (37%)
NGL (bpd) 170 203 (16%)
Natural gas (Mcfd) 10,920 14,759 (26%)
Barrels of oil equivalent (BOED) (4) 2,958 4,191 (29%)
Average prices:
Oil ($/bbl) $ 97.36 $ 84.83 15%
NGL ($/bbl) $ 69.13 $ 61.77 12%
Natural gas ($/Mcf) $ 5.01 $ 2.94 70%
Barrels of oil equivalent ($/BOE) (4) $ 54.54 $ 44.70 22%
Realized loss on derivative contracts
($/BOE) $ (1.53) $ (1.55) 1%
Royalties ($/BOE) $ 4.99 $ 4.23 18%
Operating costs ($/BOE) $ 13.28 $ 11.93 11%
Transportation costs ($/BOE) $ 0.23 $ 0.21 10%
Operating netback ($/BOE) (3) $ 34.51 $ 26.78 29%
Wells drilled (gross) 4 2 100%
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(1) Includes royalty and other income classified with oil and gas sales,
but excludes realized and unrealized gains or losses on derivative
contracts.
(2) Funds from operations, funds from operations per share, working capital
and working capital (deficiency) are considered additional GAAP
measures. Refer to the section entitled "Additional GAAP Measures" in
the Management's Discussion and Analysis ("MD&A") for a more complete
description of these additional GAAP measures. Bank loans of $nil
(March 31, 2013 - $55.1 million) were included in working capital as
defined therein.
(3) Adjusted earnings (loss) before taxes, adjusted earnings (loss) before
taxes per share and operating netback per BOE are considered non-GAAP
measures. Refer to the section entitled "Non-GAAP Measures" in the MD&A
for a more complete description of these non-GAAP terms,
reconciliations to more closely related GAAP measures, and the purposes
for which management uses the non-GAAP measures. These non-GAAP
measures may not be comparable with the calculation of similar measures
for other entities.
(4) Barrels of oil equivalent ("BOE") 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.
STRATEGY
The Company's business plan is to pursue growth of its asset base and cash flow,
and increase its financial flexibility to meet its obligations when they become
due. Coming out of the strategic alternatives process, the Company is smaller in
terms of production, has cash in the bank and an unused bank operating line. Its
convertible debentures mature in 2016 and 2017.
Admittedly, the current share price is weak. The overall market for public
junior oil and gas companies has been weak in the past few years. The share
price reflects the uncertainty associated with the recently completed strategic
alternatives process, the lack of drilling activity during the process and a
debt to cash flow ratio that is currently too high. With the bank debt issues
resolved, Anderson intends to focus on rebuilding its asset base by drilling
Cardium and Mannville horizontal light oil wells, and growing its Cardium and
Mannville horizontal oil drilling inventory in the Willesden Green, West Pembina
and Buck Lake areas. In its first full quarter since completion of the strategic
alternatives process, the Company has shown progress on all fronts with
increasing oil production, cash flow and reserves. The Company expects it will
take time for the market to appreciate the growth in annual oil production and
growth potential of its asset base. The longer term debenture maturities give
the Company time to rebuild its asset base. By resuming a drilling program and
controlling the infrastructure in its Cardium oil properties where feasible, the
Company should be able to increase oil production and operating netbacks. A
strategy of increasing oil assets, production and cash flow should also support
a higher borrowing base over time.
Anderson will continue to focus on reducing average well payouts. The goal is to
have Cardium wells pay out in approximately one year, on average, by continuing
to improve the profitability of these operations. The Company believes this goal
can be achieved by continuing to implement new approaches in Cardium horizontal
drilling and completion technologies, and by keeping costs as low as possible.
Recent technological changes include repositioning the trajectory of the
horizontal well within the Cardium zone to maximize frac effectiveness, and
using dissolvable frac balls. In 2014, the Company plans to drill its first
long-reach horizontal oil well that is expected to traverse up to 3,000 metres
of horizontal Cardium net pay. It is anticipated that long-reach horizontal
wells will access Cardium reserves in two sections of land as opposed to the
current one section of land per horizontal well. There is a capital cost benefit
to drilling an extended reach well over two sections as compared to two wells
traversing one section of land each. There is also a reserves benefit with
longer horizontal wells due to additional reservoir contact.
Where it can, the Company strives to operate its own oil and gas infrastructure
and attract third parties to utilize this infrastructure on a processing fee
basis in order to reduce overall operating costs. Currently, the Company
operates over 90% of its production and all of its current drilling operations.
Anderson is developing new light oil horizontal plays on its existing acreage in
the Mannville and Belly River and is planning to drill one of these plays in
2014.
The Company currently has no plans to dispose of its Cardium oil assets. In
addition, the Company currently has no plans to buy back common shares or
convertible debentures with normal course issuer bids. The Company's plan is to
continue to grow its asset base by investing in its light oil drilling
opportunities.
Anderson will continue to look for ways to optimize, rationalize, consolidate
and improve the profitability of its shallow gas business. In the fourth quarter
of 2013 and the first quarter of 2014, the Company disposed of unprofitable
shallow gas assets. The Company's remaining shallow gas properties are
profitable at current natural gas prices. The Company is not planning any
significant new investments in the shallow gas business, and may dispose of some
or all of its remaining shallow gas assets.
For 2014, the Company estimates that oil and NGL ("liquids") production will be
approximately 36% of total production, and that revenue from liquids will be
approximately 66% of total revenue. The Company expects the percentage
contribution of liquids to total revenue to grow, and estimates that its
production will be balanced between natural gas and liquids by the end of 2015.
WINTER DRILLING PROGRAM
This winter, Anderson embarked on a seven well drilling program. The program
started a few weeks later than planned in order to use the same drilling rig
that was used last year, which helped to keep drilling costs low. Two of the
seven wells in the program were originally planned to be on-stream in late
January, but were delayed due to a third party natural gas plant that incurred a
plant outage which lasted almost a month. The third party plant processed the
solution gas from these two wells. This outage was resolved and these two oil
wells and the related solution gas were brought on-stream a month later than
planned. The other five wells in the program were unaffected by the third party
plant outage.
The best performing well to date from this winter's drilling program averaged
697 bpd of oil, 755 bpd of oil and NGL and 1,119 BOED in its first 30 days of
initial production ("IP 30"). This well has demonstrated the best IP 30
performance of any horizontal well drilled by the Company since its entry into
the Cardium play in 2010.
Results from the program to date are shown in table below:
Average Gross IP 30
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Number of wells in average 7
Barrels of oil per day (BOPD) 241
Barrels of oil and NGL per day (BPD) 276
Barrels of oil equivalent per day (BOED) 459
----------------------------------------------------------------------------
The comparable IP 30 data for the Company' previous slick water drilling program
was 453 BOED for seven wells.
Short-term production rates can be influenced by flush production effects from
fracture stimulations in horizontal wellbores and may not be indicative of
longer-term production performance. Individual well performance may vary.
In its March 31, 2014 press release, the Company reported the potential for a 1
MMcfd production shut-in related to a National Energy Board Order imposing a
reduction in TransCanada Pipelines' maximum operating pressure on a pipeline
lateral in Central Alberta. The Operator of the gas plant on the pipeline
lateral has since informed the Company that the Company will not have its
production curtailed by this Order. The Company will continue to monitor this
situation.
LIGHT OIL HORIZONTAL DRILLING INVENTORY
The Company's undeveloped light oil horizontal drilling inventory at May 12,
2014, is outlined below:
Prospect Area (number of drilling locations) Gross Net(i)
----------------------------------------------------------------------------
Willesden Green Cardium 81 58.3
West Pembina/Buck Lake Cardium 26 7.7
Mannville/Belly River 8 7.3
----------------------------------------------------------------------------
Total Light Oil Horizontal Drilling Inventory 115 73.3
----------------------------------------------------------------------------
(i) Net is net revenue interest
GLJ booked undeveloped reserves to 22.4 net locations at April 30, 2014. The
locations booked by GLJ include 1.8 net locations related to the Mannville/Belly
River prospect area. GLJ's booked locations are included in the drilling
inventory table shown above.
Six gross (3.2 net) locations are on lands where the Company's development plan
is to drill extended reach horizontal wells traversing 1.5 to 2 miles of land.
The Company has a potential drilling inventory of 95 gross (58 net) horizontal
locations in the Second White Specks light oil play. Offsetting industry
activity has not yet proved this play to be commercial; therefore, it is not
included in the drilling inventory table above.
The Company also has an extensive shallow gas drilling inventory in the Edmonton
Sands. At the present time, the Company's business strategy does not include any
near-term plans for shallow gas drilling.
ACQUISITIONS AND DISPOSITIONS
On February 28, 2014, the Company closed a transaction whereby it disposed of
107 wellbores, 31 compressor stations and 880 Mcfd of forecasted 2014 shallow
gas production. This property had a historical operating cost of approximately
$4.00 per Mcf and average royalties of approximately 10%. This non-operated
property has generated negative cash flow in the past two years and was expected
to have negative cash flow in 2014 if not sold. This transaction is accretive on
a cash flow basis to the Company as it reduces annualized operating expenses by
$1.3 million and reduces decommissioning obligations by $3.1 million. These
lands had no further development potential.
Year-to-date, the Company has completed or committed to $1.9 million in net
property acquisitions related to Cardium and Mannville prospects, and the sale
of $0.9 million in shallow gas and undeveloped land.
2014 CAPITAL BUDGET
The Board of Directors has approved a 2014 capital budget of $46 million.
Sixty-eight percent of the budget is directed at drilling and completion
expenditures to drill 12 net Cardium and Mannville horizontal light oil drilling
prospects. Twenty-four percent of the expenditures are directed at equipping,
tie-in and facility expenditures and the remaining funds are directed at land,
abandonments and capitalized G&A expenditures. With this capital program, the
annual production guidance for 2014 has increased to approximately 3,200 BOED
(36% oil and NGL), up from the guidance provided by Company in its March 31,
2014 press release (2,600 BOED, 33% oil and NGL). The Company estimates 2014
exit production to be approximately 3,700 BOED (42% oil and NGL).
In addition to the seven well 2013/2014 Cardium winter program, the Company is
planning to drill 15 gross (12.6 net) Cardium and Mannville light oil horizontal
wells from the second quarter of 2014 to spring breakup 2015. The Company
continues to evaluate farm-in and property acquisitions in its Cardium and
Mannville light oil focus areas. Should the Company add additional farm-in
commitments, it would substitute those commitments into its 2014 capital program
and defer the current budgeted locations until 2015.
COMMODITY PRICES
A comparison of Anderson's average wellhead oil price to various market prices
is presented below. Average wellhead prices are before the impact of any
financial derivative contracts used for risk management. The difference between
Anderson's wellhead price and WTI Canadian is due to the price differential
between Cushing, Oklahoma and Edmonton, oil transportation costs from the field
to Edmonton and adjustments for oil quality.
CRUDE OIL PRICES
Three months
ended
March 31
----------------------------------------------------------------------------
2014 2013
----------------------------------------------------------------------------
WTI - $US $ 98.62 $ 94.34
WTI - $Cdn $ 108.83 $ 95.16
Differential from Cushing to Edmonton - $US per bbl $ 8.35 $ 6.91
Edmonton Par - $Cdn per bbl $ 100.04 $ 88.31
Anderson average wellhead price per bbl $ 97.36 $ 84.83
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A comparison of Anderson's average plant gate natural gas price to various
market prices is presented below. Average plant gate prices are before the
impact of any financial derivative or fixed price contracts used for risk
management. The difference between the AECO price and Anderson's plant gate
price is due to transportation costs and the heat content of the gas. Financial
derivative and fixed price contracts reduced the average price received for
natural gas to $4.59 per Mcf in the first quarter of 2014.
NATURAL GAS PRICES
Three months
ended
March 31
----------------------------------------------------------------------------
2014 2013
----------------------------------------------------------------------------
NYMEX US$ per MMBtu $ 4.72 $ 3.48
AECO $CAD per GJ 5.36 3.04
AECO $CAD per MMBtu 5.66 3.20
Anderson average plant gate price per Mcf $ 5.38 $ 2.94
----------------------------------------------------------------------------
The 2014 monthly WTI Canadian oil prices were approximately $112.14 per bbl in
April and $109.12 per bbl to date in May. Differentials from Cushing, Oklahoma
to Edmonton were approximately $8.32 US per bbl in April and $4.12 US per bbl in
May. AECO natural gas prices were approximately $4.52 per GJ ($4.77 per MMBtu)
in April and $4.45 per GJ ($4.69 per MMBtu) month to date in May.
Going forward, Anderson estimates that light oil prices will stay strong but
volatile and will be influenced by geopolitical events. Cushing, Oklahoma to
Edmonton differentials are also expected to continue to be volatile, as well as
movements in the US dollar exchange rate.
In the first quarter of 2014, North American winter weather contributed to much
stronger natural gas pricing than we have seen in recent years. The winter
weather also reduced North American natural gas storage to levels not seen for
many years. This should contribute to stronger natural gas pricing this summer
compared to recent prior years.
Natural gas prices are influenced by weather events and are tempered by the
increasing supply of new shale gas. Until meaningful exports of natural gas
commence from North America through liquefied natural gas projects, the Company
believes that natural gas prices will be range-bound by weather events.
FINANCIAL RESULTS
Funds from operations were $5.5 million in the first quarter of 2014 as compared
to $(0.3) million in the fourth quarter of 2013. On a BOE basis, oil and gas
sales averaged $54.54 per BOE in the first quarter of 2014 compared to $36.49
per BOE in the fourth quarter of 2013. During the first quarter of 2014, oil and
NGL revenue represented 66% of total revenue. The Company's operating netback
was $34.51 per BOE in the first quarter of 2014 as compared to $14.81 per BOE
for the fourth quarter of 2013 ($12.35 per BOE excluding properties sold in the
fourth quarter of 2013). Both quarters were negatively impacted by losses on
financial derivative or fixed price contracts (2014 - $2.91 per BOE, 2013 -
$2.96 per BOE). The increase in operating netback was primarily driven by higher
oil and gas prices. Anderson's operating netback for Cardium properties in the
first quarter of 2014 was $60.30 per BOE as compared to $39.54 per BOE in the
fourth quarter of 2013 ($38.55 per BOE adjusted for properties sold in the
fourth quarter of 2013), exclusive of hedging.
The Company reported earnings of $0.5 million in the first quarter of 2014
compared to a loss of $2.4 million in the fourth quarter of 2013 and a loss of
$5.1 million for the first quarter of 2013.
Field capital expenditures were $14.5 million in the first quarter of 2014 as
compared to $7.4 million in the fourth quarter of 2013. Capital investments in
the first quarter of 2014 were focused primarily on the drilling, completion,
equipping and tie-in of Cardium horizontal oil wells. In the first quarter of
2014, the Company spent $1.0 million net of dispositions on the acquisition of
undeveloped land and producing properties as opposed to net dispositions of
$79.8 million in the fourth quarter of 2013.
HEDGING
Derivative contracts
At March 31, 2014, the following fixed price swap contract based on the AECO 5A
natural gas price was outstanding and recorded at estimated fair value:
Weighted Weighted
average average
volume Canadian
Period (GJ/d) ($/GJ)
----------------------------------------------------------------------------
April 1, 2014 to December 31, 2014 2,500 $ 3.55
----------------------------------------------------------------------------
Subsequent to March 31, 2014 the Company entered into the following derivative
contract for crude oil:
Weighted
Weighted average WTI
average Canadian
Period volume (bpd) ($/bbl)
----------------------------------------------------------------------------
May 1, 2014 to December 31, 2014 500 $ 110.00
----------------------------------------------------------------------------
Fixed price contracts
The Company entered into physical contracts to sell 2,500 GJs per day of natural
gas for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72
per GJ. All of the remaining natural gas production is being sold at the monthly
average of AECO 5A daily index prices.
RESERVES
GLJ Petroleum Consultants ("GLJ"), an independent evaluator, has completed a
modified corporate look-ahead analysis of the Company's reserves (the "GLJ
Interim Report"). The previous 2013 year end evaluation has been updated to an
April 30, 2014 effective date, utilizing GLJ's April 1, 2014 price deck and a
modified "look ahead" analysis approach. More details on the methodology
followed under this approach are provided in Management's Discussion and
Analysis for the three months ended March 31, 2014. The GLJ Interim Report was
prepared for the Company for the purpose of providing a corporate update and is
not the equivalent of a full year end reserves report. At April 30, 2014, the
Company had 3,811 MBOE PDP reserves (33% oil and NGL), 5,472 MBOE TP reserves
(36% oil and NGL) and 9,583 MBOE P&P reserves (43% oil and NGL). The GLJ price
forecast used in the evaluation is shown in Management's Discussion and Analysis
for the three months ended March 31, 2014.
The increased reserves in the GLJ Interim Report reflect the impact of the
winter drilling program, higher commodity price forecasts, and additional
drilling locations associated with recent property acquisitions. The Cardium
formation represents approximately 47%, 51% and 63% respectively of PDP, TP and
P&P total BOE reserves volumes and 79%, 80% and 82% respectively of the total
Company PDP, TP and P&P NPV 10 value.
SUMMARY OF OIL AND GAS RESERVES
April 30, 2014
----------------------------------------------------------------------------
Pre-tax
Gross Working Interest Oil NGL Gas Total NPV 10
Oil and Gas Reserves (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)
----------------------------------------------------------------------------
Proved developed producing 1,020 246 15,269 3,811 63,375
Proved developed non-producing 53 34 4,176 784 6,660
Total proved 1,624 341 21,043 5,472 81,097
Proved plus probable 3,469 643 32,829 9,583 132,813
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December 31, 2013
-------------------------------------------------------------------------
Pre-tax
Gross Working Interest Oil NGL Gas Total NPV 10
Oil and Gas Reserves (Mbbls) (Mbbls) (MMcf) (MBOE) ($M)
-------------------------------------------------------------------------
Proved developed producing 792 216 14,639 3,447 43,153
Proved developed non-producing 128 25 3,683 767 7,527
Total proved 1,608 313 20,336 5,311 61,608
Proved plus probable 3,150 565 30,642 8,822 100,312
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UNDEVELOPED LAND
Anderson has 226,343 gross (132,355 net) developed acres and 65,048 gross
(27,988 net) undeveloped acres of land at December 31, 2013. Undeveloped land
was valued at $3.4 million by management at the end of 2013.
ANNUAL GENERAL MEETING
The Company's annual shareholders' meeting (the "Meeting") is scheduled for
10:00 a.m. on June 18, 2014 at the Westwinds Conference Room, 2nd Floor Selkirk
House, 555 4th Avenue S.W., Calgary, Alberta.
On May 12, 2014, the Company's Board of Directors approved an advance notice
by-law (the "By-Law") which will apply to nominations of directors at the
Meeting. The By-Law is in effect until it is confirmed, confirmed as amended or
rejected by shareholders at the Meeting. Additional details will be provided in
the Company's management information circular to be distributed prior to the
Meeting.
SUMMARY
The Company has made considerable progress in the last few months by
demonstrating oil production growth, oil reserves growth and reserves value
growth. Anderson is now embarking on a significant high impact Cardium and
Mannville horizontal oil drilling program. The Company continues to rationalize
and improve the profitability of its shallow gas assets and add to its
horizontal light oil drilling inventory with farm-in and property acquisitions.
The management and staff are very excited about the future oil production growth
drilling program and the Company's prospects in the Willesden Green Cardium and
Mannville plays.
For further information on the Company, please refer to the investor
presentation at www.andersonenergy.ca.
Brian H. Dau, President & Chief Executive Officer
May 13, 2014
Management's Discussion and Analysis
FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013
The following management's discussion and analysis ("MD&A") is dated May 12,
2014 and should be read in conjunction with the unaudited condensed interim
consolidated financial statements of Anderson Energy Ltd. ("Anderson" or the
"Company") for the three months ended March 31, 2014 and the audited
consolidated financial statements and MD&A of Anderson for the years ended
December 31, 2013 and 2012.
In addition to generally accepted accounting principles ("GAAP") measures, this
MD&A contains additional conversion measures, non-GAAP measures, additional GAAP
measures and forward-looking statements. Readers are cautioned that the MD&A
should be read in conjunction with Anderson's disclosure under the headings
"Conversion Measures," "Non-GAAP Measures," "Additional GAAP Measures" and
"Forward-Looking Statements" included at the end of this MD&A.
All references to dollar values are to Canadian dollars unless otherwise stated.
Production volumes are measured upon sale unless otherwise noted. Definitions of
the abbreviations used in this discussion and analysis are located on the last
page of this document.
REVIEW OF FINANCIAL RESULTS
Overview
Anderson completed its seven well winter drilling program in the first quarter.
These horizontal Cardium wells contributed to a significant increase in oil
production, funds from operations and reserves from the fourth quarter of 2013.
The Company ended the first quarter of 2014 with no bank debt and a working
capital deficiency(1) of $1.0 million at March 31, 2014, compared to bank loans
plus a working capital deficiency of $66.8 million at March 31, 2013. During the
three month period ended March 31, 2014, the Company generated $5.5 million in
funds from operations(2) and reported earnings of $0.5 million. The Company also
invested $16.0 million in capital expenditures net of minor property
dispositions.
Asset dispositions in the fourth quarter of 2013 that impacted production
volumes and financial results in the first quarter of 2014 included the sale of
the Garrington and Ferrier Cardium oil and natural gas properties that had
produced approximately 1,000 BOED (65% oil and NGL), and the sale of shallow gas
properties that produced approximately 860 Mcfd (143 BOED). In the first quarter
of 2014, the Company disposed of a further 880 Mcfd (147 BOED) of unprofitable
shallow gas production.
In light of the recent changes in the Company's assets and production profile
due to the sale of properties in the fourth quarter of 2013, the 2013/2014
winter drilling program, and higher commodity prices, a comparison to the fourth
quarter of 2013 has been added to the following table, "Summary of Production,
Prices, Sales, and Funds from Operations", to provide additional clarity as to
the variables contributing to the Company's improved financial performance
during the three months ended March 31, 2014 from the previous three-month
period ended December 31, 2013.
(1) Working capital or working capital (deficiency) are considered
additional GAAP measures. Refer to the section entitled "Additional
GAAP Measures" at the end of this MD&A.
(2) Funds from operations are considered an additional GAAP measure. Refer
to "Funds from Operations" in this section and the section entitled
"Additional GAAP Measures" at the end of this MD&A.
SUMMARY OF PRODUCTION, PRICES, REVENUE, AND FUNDS FROM OPERATIONS
Production
Three months ended
March 31 December 31 March 31
----------------------------------------------------------------------------
2014 2013 2013
----------------------------------------------------------------------------
Oil (bpd) 969 537 1,529
NGL (bpd) 170 166 203
Natural gas (Mcfd) 10,920 10,467 14,759
----------------------------------------------------------------------------
Total (BOED)(5) 2,958 2,448 4,191
----------------------------------------------------------------------------
Prices
Three months ended
March 31 December 31 March 31
----------------------------------------------------------------------------
2014 2013 2013
----------------------------------------------------------------------------
Oil ($/bbl)(1) $ 97.36 $ 84.26 $ 84.83
NGL ($/bbl) 69.13 61.60 61.77
Natural gas ($/Mcf)(1)(2) 5.01 3.19 2.94
----------------------------------------------------------------------------
Total ($/BOE)(3)(5) $ 54.54 $ 36.49 $ 44.70
----------------------------------------------------------------------------
Oil and gas sales
Three months ended
March 31 December 31 March 31
----------------------------------------------------------------------------
(thousands of dollars) 2014 2013 2013
----------------------------------------------------------------------------
Oil(1) $ 8,487 $ 4,162 $ 11,671
NGL 1,057 943 1,129
Natural gas(1)(2) 4,920 3,067 3,902
Royalty and other 58 45 161
----------------------------------------------------------------------------
Total oil and gas sales $ 14,522 $ 8,217 $ 16,863
----------------------------------------------------------------------------
Funds from operations
Three months ended
March 31 December 31 March 31
----------------------------------------------------------------------------
(thousands of dollars) 2014 2013 2013
----------------------------------------------------------------------------
Cash from operating activities $ 2,375 $ (230) $ 5,171
Changes in non-cash working
capital 2,982 (671) 239
Decommissioning expenditures 181 595 76
----------------------------------------------------------------------------
Funds from operations(4) $ 5,538 $ (306) $ 5,486
----------------------------------------------------------------------------
1. Excludes the realized loss of $0.4 million and unrealized loss of $0.5
million on natural gas derivative contracts, respectively during the
three months ended March 31, 2014 (December 31, 2013 - $0.9 million loss
and $0.9 million gain on oil contracts respectively) (March 31, 2013 -
$0.6 million loss and $1.1 million loss on oil contracts, respectively).
2. Includes loss on fixed price natural gas contracts of $0.4 million
during the three months ended March 31, 2014 (December 31, 2013 and
March 31, 2013 - $nil).
3. Includes royalty and other income classified with oil and gas sales.
4. Funds from operations are considered an additional-GAAP measure Refer to
"Funds from Operations" in this section and the section entitled
"Additional GAAP Measures" at the end of this MD&A.
5. Barrels of oil equivalent ("BOE") may be misleading, particularly if
used in isolation. Refer to the section entitled "Conversion Measures"
at the end of this MD&A.
Production
Average production volumes in the first quarter of 2014 were 2,958 BOED compared
to 2,448 BOED in the fourth quarter of 2013 and 4,191 BOED in the first quarter
in 2013.
Properties sold in the fourth quarter of 2013 contributed approximately 336 BOED
to the production reported the fourth quarter of 2013.
Overall, production volumes in the first quarter of 2014 decreased 29% compared
to the first quarter of 2013, but increased 21% from volumes reported in the
fourth quarter of 2013 (40% net of production from sold properties).
The first quarter of 2014 has benefitted from increased oil production as a
result of the 2013/2014 winter drilling program. One of the seven wells in the
winter drilling program came on-stream in December 2013 and the remaining six
wells came on-stream at various times during the first quarter of 2014.
As discussed more fully in the "Business Prospects" section later in this MD&A,
the Company has revised its 2014 capital program, and has increased its 2014
production guidance to approximately 3,200 BOED (36% oil and NGL), up from the
guidance provided by Company in its March 31, 2014 press release (2,600 BOED,
33% oil and NGL). The Company estimates 2014 exit production to be approximately
3,700 BOED (42% oil and NGL).
In its March 31, 2014 press release, the Company reported the potential for a 1
MMcfd production shut-in related to a National Energy Board Order imposing a
reduction in TransCanada Pipelines' maximum operating pressure on a pipeline
lateral in Central Alberta. The Operator of the gas plant on the pipeline
lateral has since informed the Company that the Company will not have its
production curtailed by this Order. The Company will continue to monitor this
situation.
Prices
World and North American benchmark prices for oil remain volatile. Differentials
between WTI oil prices and prices received in Alberta are also volatile due to
factors including refining demand and pipeline capacity. Anderson sells its oil
at monthly average Edmonton Par prices less quality differentials,
transportation and marketing fees. Light, sweet oil differentials between
Cushing, Oklahoma and Edmonton, Alberta are affected by transportation and
market factors. Differentials in the first quarter of 2014 averaged $8.35 US
discount per bbl (March 31, 2013 - $6.91 US per bbl).
Natural gas prices improved significantly in the first few months of 2014 due to
higher demand related to colder weather conditions in North America, but longer
term markets have not seen the same increase. In the first quarter of 2014, AECO
5A prices averaged approximately $5.36 Cdn per GJ. Forward strip prices for AECO
are approximately $3.95 Cdn per GJ for 2015 and $3.80 Cdn per GJ for 2016.
The Company's average natural gas sales price was $5.01 per Mcf for the three
months ended March 31, 2014, 57% higher than the fourth quarter of 2013 price of
$3.19 per Mcf and 70% higher than the first quarter of 2013 price of $2.94 per
Mcf. This price includes the effect of the fixed price contracts discussed
below. The average price before the effect of the fixed price contracts was
$5.38 per Mcf. The average price after the effect of both the fixed price
contracts and the derivative contracts discussed below was $4.59 per Mcf.
Derivative contracts
At March 31, 2014, the following fixed price swap contract based on the AECO 5A
natural gas price was outstanding and recorded at estimated fair value:
Weighted Weighted
average volume average Cdn
Period (GJ/d) ($/GJ)
----------------------------------------------------------------------------
April 1, 2014 to December 31, 2014 2,500 $ 3.55
----------------------------------------------------------------------------
By comparison, AECO 5A averaged $5.36 Cdn per GJ in the first quarter of 2014
and $3.35 Cdn per GJ in the fourth quarter of 2013. During 2014, AECO 5A has
averaged $4.06 Cdn per GJ for January, $7.19 Cdn per GJ for February and $5.01
Cdn per GJ in March.
Derivative contracts on natural gas had the following impact on the unaudited
consolidated statements of operations for the three months ended March 31, 2014
(the comparative numbers for the three months ended March 31, 2013 were on oil
derivative contracts):
Three months ended
March 31
----------------------------------------------------------------------------
(thousands of dollars) 2014 2013
----------------------------------------------------------------------------
Realized loss on derivative contracts $ 407 $ 586
Unrealized loss on derivative contracts 464 1,071
----------------------------------------------------------------------------
Total loss on derivative contracts $ 871 $ 1,657
----------------------------------------------------------------------------
Subsequent to March 31, 2014 the Company entered into the following derivative
contract for crude oil:
Weighted
Weighted average WTI
average Canadian
Period volume (bpd) ($/bbl)
----------------------------------------------------------------------------
May 1, 2014 to December 31, 2014 500 $ 110.00
----------------------------------------------------------------------------
Fixed price contracts
The Company entered into physical contracts to sell 2,500 GJs per day of natural
gas for January 1, 2014 to December 31, 2014 at an average AECO price of $3.72
Cdn per GJ. All of the remaining natural gas production is being sold at the
monthly average of AECO 5A daily index prices.
Royalties
For the first quarter of 2014, the average rate for royalties was 8.9% of
revenue compared to 11.3% of revenue in the fourth quarter of 2013 and 9.5% of
revenue in the first quarter of 2013. Oil wells drilled by the Company on Crown
lands qualify for royalty incentives that reduce average Crown royalties for
periods of up to 36 months from initial production, after which Crown royalties
are expected to increase from current levels.
Royalties as a percentage of total oil and gas sales are highly sensitive to
prices and adjustments to gas cost allowance and so royalty rates can fluctuate
from quarter to quarter and year to year.
Three months ended
March 31
----------------------------------------------------------------------------
2014 2013
----------------------------------------------------------------------------
Gross Crown royalties 6.9% 5.3%
Gas cost allowance (2.0%) (1.3%)
Other royalties 4.0% 5.5%
----------------------------------------------------------------------------
Total royalties 8.9% 9.5%
Total royalties ($/BOE) $ 4.99 $ 4.23
----------------------------------------------------------------------------
Operating expenses
Operating expenses were $3.5 million ($13.28 per BOE) in the first quarter of
2014 compared to $3.2 million ($14.31 per BOE) in the fourth quarter of 2013 and
$4.5 million ($11.93 per BOE) in the first quarter of 2013. Operating expenses
on a per BOE basis were affected by the impact of the property sales on the
product sales mix of the Company. The oil properties sold by the Company during
the fourth quarter of 2013 generally contributed to lower operating costs per
BOE than many of the Company's natural gas properties. Following the sale of the
oil properties, the Company had a larger proportion of natural gas properties
that contributed to higher operating costs per BOE. As expected, the winter
drilling program in the Cardium formation resulted in a greater proportion of
operating costs and volumes from the Cardium areas, thereby lowering the
Company's average operating costs on a per BOE basis during the first quarter of
2014 compared to the fourth quarter of 2013. The disposition of high operating
cost natural gas properties in the first quarter of 2014 should help to lower
operating costs per BOE in future quarters.
Transportation expenses
For the first quarter of 2014, transportation expenses were $0.23 per BOE
compared to $0.28 per BOE in the fourth quarter of 2013 and $0.21 per BOE in the
first quarter of 2013. The increase in transportation expenses in the first
quarter of 2014 compared to the first quarter of 2013 was due to higher NGL
trucking costs. Also, following the sale of the Garrington and Ferrier
properties in the fourth quarter of 2013, the remainder of the Company's
production from oil properties has been trucked to the point of sale.
OPERATING NETBACK
Three months ended
March 31
---------------------------------------------------------------------------
(thousands of dollars) 2014 2013
---------------------------------------------------------------------------
Revenue(1)(2)(3) $ 14,522 $ 16,863
Realized loss on derivative contracts (407) (586)
Royalties (1,327) (1,595)
Operating expenses (3,536) (4,503)
Transportation expenses (62) (77)
---------------------------------------------------------------------------
Operating netback(4) $ 9,190 $ 10,102
---------------------------------------------------------------------------
Sales volume (MBOE)(5) 266.3 377.2
Per BOE(5)
Revenue(1)(2)(3) $ 54.54 $ 44.70
Realized loss on derivative contracts (1.53) (1.55)
Royalties (4.99) (4.23)
Operating expenses (13.28) (11.93)
Transportation expenses (0.23) (0.21)
---------------------------------------------------------------------------
Operating netback(4) $ 34.51 $ 26.78
---------------------------------------------------------------------------
1. Excludes the realized loss of $0.4 million and unrealized loss of $0.5
million on natural gas derivative contracts, respectively during the
three months ended March 31, 2014 (March 31, 2013 - $0.6 million loss
and $1.1 million loss on oil contracts, respectively).
2. Includes loss on fixed price natural gas contracts of $0.4 million
during the three months ended March 31, 2014 (March 31, 2013 - $nil).
3. Includes royalty and other income classified with oil and gas sales.
4. Operating netback is considered a non-GAAP measure. Refer to the section
entitled "Non-GAAP Measures" at the end of this MD&A.
5. Barrels of oil equivalent ("BOE") may be misleading, particularly if
used in isolation. Refer to the section entitled "Conversion Measures"
at the end of this MD&A.
Depletion and depreciation
Depletion and depreciation was $5.7 million ($21.23 per BOE) in the first
quarter of 2014 compared to $4.3 million ($19.27 per BOE) in the fourth quarter
of 2013 and $8.6 million ($22.83 per BOE) in the first quarter of 2013. The
decrease in the amount of depletion and depreciation for the first quarter of
2014 compared to the three months ended March 31, 2013 was due to the asset
sales in the fourth quarter of 2013 and lower overall production volumes. Proved
plus probable reserves volumes are included in the determination of depletion
expense.
Impairment losses
At March 31, 2014, there were no indicators of impairment or reversals of
impairment in the Company's CGUs; thus, no impairment test or reversal of
impairment calculation was performed.
General and administrative expenses
As detailed at the end of this MD&A, general and administrative (cash) ("G&A
(cash)") expenses is a term that does not have any standardized meaning under
GAAP. Refer to the section entitled "Non-GAAP Measures" found at the end of this
MD&A.
G&A (cash) expenses were $1.9 million ($6.98 per BOE) in the first quarter of
2014 compared to $1.5 million ($6.54 per BOE) for the fourth quarter of 2013 and
$2.1 million ($5.45 per BOE) for the first quarter of 2013. G&A (cash) expenses
were higher than the fourth quarter of 2013 due to the timing of bonus payments
to staff but were lower than the first quarter of 2013 due to lower overall
staffing levels. In addition, overhead recoveries are lower in the first quarter
of 2014 due to the asset sales in the fourth quarter of 2013. Capitalized
general and administrative costs consist of salaries, benefits and office rent
associated with staff involved in capital activities.
The following table is a reconciliation of the Company's G&A (cash) expenses to
general and administrative expenses:
Three months ended
March 31
---------------------------------------------------------------------------
(thousands of dollars) 2014 2013
---------------------------------------------------------------------------
Gross G&A (cash) expenses $ 2,459 $ 2,764
Overhead recoveries (145) (241)
Capitalized (455) (468)
---------------------------------------------------------------------------
Net G&A (cash) expenses(1) $ 1,859 $ 2,055
Net share-based compensation 82 197
---------------------------------------------------------------------------
General and administrative expenses $ 1,941 $ 2,252
---------------------------------------------------------------------------
G&A (cash) expenses ($/BOE)(1) $ 6.98 $ 5.45
% Capitalized 19% 17%
---------------------------------------------------------------------------
1. General and administrative (cash) expenses is considered a non-GAAP
measure. Refer to the section entitled "Non-GAAP Measures" at the end of
this MD&A.
Subsequent to March 31, 2014, the Company entered into an agreement to lease new
office space at a cost of approximately two-thirds of renewing at its existing
premises. The agreement is effective for July 2014 and is subject to the
completion of certain customary documentation.
Share-based compensation
Share-based compensation costs were $0.1 million ($0.1 million net of amounts
capitalized) for the first quarter of 2014 and $0.1 million for the fourth
quarter of 2013 (nil net of amounts capitalized) versus $0.3 million ($0.2
million net of amounts capitalized) in the first quarter of 2013.
Finance expenses
Finance expenses were $2.6 million for the first quarter of 2014, compared to
$2.9 million for the fourth quarter of 2013 and $3.3 million in the first
quarter of 2013. The decrease in finance expenses from the first quarter of 2013
is the result of lower interest and other financing charges associated with bank
credit facilities. Proceeds from the disposition of assets in the fourth quarter
of 2013 were used to repay bank debt, and the Company has had no outstanding
bank loans since October 2013. Interest expense on credit facilities in the
first quarter of 2014 includes stand-by and other fees associated with
maintaining the existing bank line of $28 million.
Three months ended
March 31
----------------------------------------------------------------------------
(thousands of dollars) 2014 2013
----------------------------------------------------------------------------
Interest and accretion on convertible
debentures $ 2,366 $ 2,295
Interest expense on credit facilities and
other 81 791
Accretion on decommissioning obligations 192 188
----------------------------------------------------------------------------
Finance expenses $ 2,639 $ 3,274
----------------------------------------------------------------------------
Decommissioning obligations
The decommissioning liability at March 31, 2014 was lower than at December 31,
2013 due to the disposition of certain natural gas properties in the first
quarter of 2014 that carried $3.1 million of decommissioning obligations at
December 31, 2013.
Accretion expense was $0.2 million in the first quarter of 2014, provisions
incurred were $0.4 million and actual expenditures were $0.2 million.
The risk-free discount rates used by the Company to measure the obligations at
March 31, 2014 were between 1.0% and 3.3% (December 31, 2013 - 1.1% to 3.2%)
depending on the timelines to reclamation and changed from the start of the year
as a result of changes in the Canadian bond market.
Income taxes
The Company has recognized a deferred tax asset in the amount of $2.0 million as
at March 31, 2014 and December 31, 2013. No additional deferred tax assets were
recognized during the first quarter of 2014. The Company has approximately $365
million of tax pools at March 31, 2014.
Funds from operations
As detailed at the end of this MD&A, "funds from operations" is a term that does
not have any standardized meaning under GAAP. Funds from operations is
calculated as cash flow from operating activities before changes in non-cash
working capital and decommissioning obligations incurred. Refer to the section
entitled "Additional GAAP Measures" found at the end of this MD&A.
The following table is a reconciliation of the Company's cash flow from
operating activities to funds from operations:
Three months ended
March 31
----------------------------------------------------------------------------
(thousands of dollars) 2014 2013
----------------------------------------------------------------------------
Cash from operating activities $ 2,375 $ 5,171
Changes in non-cash working capital 2,982 239
Decommissioning expenditures 181 76
----------------------------------------------------------------------------
Funds from operations $ 5,538 $ 5,486
----------------------------------------------------------------------------
As expected, following the asset dispositions, funds from operations were a
negative outflow of $0.3 million in the fourth quarter of 2013. Due to the
impact of higher production resulting from the winter drilling program, and
higher commodity prices during the first quarter of 2014, funds from operations
were $5.5 million ($0.03 per share) in the first quarter of 2014 versus $5.5
million ($0.03 per share) in the first quarter of 2013.
Earnings
The Company reported earnings of $0.5 million in the first quarter of 2014
compared to a loss of $2.4 million in the fourth quarter of 2013 and a loss of
$5.1 million for the first quarter of 2013. Earnings included a gain on sale of
property, plant and equipment of $2.0 million in the first quarter of 2014,
compared to $1.9 million in the fourth quarter of 2013 and almost nil in the
first quarter of 2013. An unrealized loss on derivative contracts of $0.5
million was recorded in the first quarter of 2014, compared to a $0.9 million
gain in the fourth quarter of 2013 and $1.1 million loss in the first quarter of
2013.
CAPITAL EXPENDITURES
The Company invested $16.0 million in capital expenditures net of minor property
dispositions in first quarter of 2014. The breakdown of expenditures is shown
below:
Three months ended
March 31
---------------------------------------------------------------------------
(thousands of dollars) 2014 2013
---------------------------------------------------------------------------
Land, geological and geophysical costs $ 740 $ 47
Acquisitions 378 -
Drilling, completion and recompletion 10,970 5,324
Facilities and well equipment 3,528 1,830
Capitalized G&A 455 468
---------------------------------------------------------------------------
$ 16,071 $ 7,669
Change in compressor and other equipment
inventory - (14)
Office equipment and furniture 11 7
Proceeds on disposition (50) -
---------------------------------------------------------------------------
Total net capital expenditures $ 16,032 $ 7,662
---------------------------------------------------------------------------
Drilling statistics are shown below:
Three months ended
March 31
----------------------------------------------------------------------------
2014 2013
----------------------------------------------------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------
Oil 4 4.0 2 1.8
Gas - - - -
Dry - - - -
----------------------------------------------------------------------------
Total 4 4.0 2 1.8
----------------------------------------------------------------------------
Success rate 100% 100% 100% 100%
----------------------------------------------------------------------------
The Company completed its winter drilling program with an additional 4 gross
(4.0 net capital, 4.0 net revenue) wells drilled during the first quarter of
2014. In the fourth quarter of 2013, the Company drilled 3 gross (3.0 net
capital) Cardium horizontal wells.
On February 28, 2014, the Company closed a transaction whereby it disposed of
107 wellbores, 31 compressor stations and 880 Mcfd of forecasted 2014 shallow
gas production. This non-operated property had generated negative cash flow in
the past two years and was expected to have negative cash flow in 2014 if not
sold. The lands had no further development potential.
Subsequent to March 31, 2014, the Company closed or signed letters of intent for
$1.1 million in property acquisitions and $0.9 million in property dispositions,
largely for drilling prospects on undeveloped land.
RESERVES
Subsequent to March 31, 2014, GLJ Petroleum Consultants ("GLJ"), an independent
evaluator, completed a modified corporate look-ahead analysis of the Company's
reserves (the "GLJ Interim Report"). The previous 2013 year end evaluation has
been updated to an April 30, 2014 effective date, utilizing GLJ's April 1, 2014
price deck and a modified "look ahead" analysis approach. Under this approach,
all properties, with the exception of the Edmonton Sands and Willesden Green
properties, were mechanically looked-ahead from the original December 31, 2013
effective date (which utilized the GLJ January 1, 2014 price deck) without any
adjustments for differences between actual production and GLJ forecast
production or financial operating conditions. The Edmonton Sands properties were
also mechanically looked-ahead but adjustments were made to the production
forecasts to match actual production associated with the first quarter 2014
re-activation of several wells within these properties. The Willesden Green
property evaluation was updated to include the property acquisitions and farm-in
completed as of April 30, 2014. In addition to including reserves for the
acquired lands, several existing reserves entities were converted from a
non-producing to a producing category and reserves were added for certain
drilled locations that previously had not been booked in the 2013 year end
reserves report. The report was prepared for the Company for the purpose of
providing a corporate update. The reserves definitions used in preparing the GLJ
Interim Report are those contained in the Canadian Oil and Gas Evaluation
Handbook. This is not a year end reserves report.
At April 30, 2014, the Company had 3,811 MBOE PDP reserves (33% oil and NGL),
5,472 MBOE TP reserves (36% oil and NGL) and 9,583 MBOE P&P reserves (43% oil
and NGL). The GLJ price forecast used in the evaluation is shown below.
The increased reserves in the GLJ Interim Report reflect the impact of the
winter drilling program, higher commodity price forecasts, and additional
drilling locations associated with recent property acquisitions. The Cardium
formation represents approximately 47%, 51% and 63% respectively of PDP, TP and
P&P total BOE reserves volumes and 79%, 80% and 82% respectively of the total
Company PDP, TP and P&P NPV 10 value.
SUMMARY OF GROSS WORKING INTEREST OIL AND GAS RESERVES (1)
April 30, 2014
----------------------------------------------------------------------------
Natural Before
Gas Natural Total tax NPV
Oil Liquids Gas(2) BOE(3) 10%(4)
(Mbbls) (Mbbls) (MMcf) (MBOE) ($M)
----------------------------------------------------------------------------
Proved developed producing 1,020 246 15,269 3,811 63,375
Proved developed non-producing 53 34 4,176 784 6,660
Proved undeveloped 551 61 1,598 878 11,062
----------------------------------------------------------------------------
Total proved 1,624 341 21,043 5,472 81,097
Probable 1,845 302 11,786 4,111 51,716
----------------------------------------------------------------------------
Total proved plus probable 3,469 643 32,829 9,583 132,813
----------------------------------------------------------------------------
December 31, 2013
---------------------------------------------------------------------------
Natural Before
Gas Natural Total tax NPV
Oil Liquids Gas(2) BOE(3) 10%(4)
(Mbbls) (Mbbls) (MMcf) (MBOE) ($M)
---------------------------------------------------------------------------
Proved developed producing 792 216 14,639 3,447 43,153
Proved developed non-producing 128 25 3,683 767 7,527
Proved undeveloped 688 72 2,015 1,097 10,927
---------------------------------------------------------------------------
Total proved 1,608 313 20,336 5,311 61,608
Probable 1,541 252 10,307 3,512 38,705
---------------------------------------------------------------------------
Total proved plus probable 3,150 565 30,642 8,822 100,312
---------------------------------------------------------------------------
1. Columns may not add due to rounding.
2. Coal Bed Methane is not material to report separately and is included in
the Natural Gas category.
3. Barrels of oil equivalent ("BOE") may be misleading, particularly if
used in isolation. Refer to the section entitled "Conversion Measures"
at the end of this MD&A.
4. The estimated future annual cash flows determined by the independent
reserves evaluators include assumptions and estimates related to future
revenues, royalties, other items of income, operating costs, net capital
investments and well abandonment costs for all wells with reserves at
the property level. Additional abandonment costs associated with non-
reserves wells, lease reclamation costs and facility abandonment and
reclamation expenses have not been included in the analysis. The
estimated net present value of future net revenues presented in the
table above does not necessarily represent the fair market value of the
Company's reserves. Refer to the Company's Annual Information Form for a
more complete description of the determination of the reserves values.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at April 1, 2014
GLJ Forecast Prices and Costs
Natural
Oil Gas Edmonton Liquids Prices
----------------------------------------------------------------------------
Light,
Sweet AECO
WTI Crude Gas Pentanes Exchange
Cushing Edmonton Price Propane Butane Plus Inflation rate
($US/ ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ Rate ($US/
Year bbl) bbl) MMBtu) bbl) bbl) bbl) % $Cdn)
----------------------------------------------------------------------------
2014
(Q2-
Q4) 97.50 102.78 4.64 56.53 77.08 113.06 2.0 0.900
2015 97.50 102.78 4.50 56.53 80.17 113.06 2.0 0.900
2016 97.50 105.56 4.75 58.06 82.33 112.94 2.0 0.900
2017 97.50 105.56 5.00 58.06 82.33 112.94 2.0 0.900
2018 97.50 105.56 5.25 58.06 82.33 112.94 2.0 0.900
2019 97.50 105.56 5.50 58.06 82.33 112.94 2.0 0.900
2020 98.54 106.37 5.63 58.50 82.97 113.81 2.0 0.900
2021 100.51 108.49 5.74 59.67 84.62 116.08 2.0 0.900
2022 102.52 110.66 5.85 60.86 86.31 118.40 2.0 0.900
2023 104.57 112.87 5.97 62.08 88.04 120.77 2.0 0.900
----------------------------------------------------------------------------
Thereafter 2%
----------------------------------------------------------------------------
SHARE INFORMATION
The Company's shares have been listed on the Toronto Stock Exchange since
September 7, 2005 under the symbol "AXL". As of May 12, 2014, there were 172.5
million common shares outstanding, 15.2 million stock options outstanding, $50.0
million principal amount of convertible debentures which are convertible into
common shares at a conversion price of $1.55 per common share and $46.0 million
principal amount of convertible debentures which are convertible into common
shares at a conversion price of $1.70 per common share. During the first quarter
of 2013 and 2014, no common shares were issued through the exercise of employee
stock options.
SHARE PRICE ON TSX
Three months ended March 31
----------------------------------------------------------------------------
2014 2013
----------------------------------------------------------------------------
High $ 0.28 $ 0.25
Low $ 0.13 $ 0.17
Close $ 0.24 $ 0.19
Volume 19,978,551 6,360,434
Shares outstanding at March 31 172,549,701 172,549,701
Market capitalization at March 31 $ 41,411,928 $ 31,921,695
----------------------------------------------------------------------------
The statistics above include trading on the Toronto Stock Exchange only. Shares
also trade on alternative platforms like Alpha, Chi-X, Pure and Omega.
Approximately 12.5 million common shares traded on these alternative exchanges
in the three months ended March 31, 2014 (March 31, 2013 - 3.4 million).
Including these exchanges, an average of 523,223 common shares traded per day in
the three months ended March 31, 2014 (March 31, 2013 - 160,366), representing a
quarterly turnover ratio of 19% (March 31, 2013 - 6%).
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2014, the Company had no outstanding bank loans, convertible
debentures of $96.0 million (principal) and a working capital deficiency of $1.0
million. Proceeds from property dispositions in the fourth quarter of 2013 were
used to repay the credit facilities, and the excess cash will be used to help
fund the 2013/2014 drilling program. The following table shows the changes in
bank loans plus working capital (deficiency):
Three months ended
---------------------------------------------------------------------------
March 31, December 31,
(thousands of dollars) 2014 2013
---------------------------------------------------------------------------
Bank loans plus working capital
(deficiency), beginning of period $ 9,682 $ 16,499
Funds from operations 5,538 (306)
Net proceeds on disposition of assets
(capital expenditures) (16,032) 71,972
Change in assets held for sale included in
working capital (deficiency) - (84,196)
Change in decommissioning obligations held
for sale included in working capital
(deficiency) - 6,308
Decommissioning expenditures (181) (595)
----------------------------
Bank loans plus working capital
(deficiency), end of period $ (993) $ 9,682
----------------------------
Bank loans, end of period $ - $ -
Working capital (deficiency), end of period (993) 9,682
----------------------------
Bank loans plus working capital
(deficiency), end of period $ (993) $ 9,682
---------------------------------------------------------------------------
The continued development of the Company's oil and gas assets is dependent on
the ability of the Company to secure sufficient funds through operations, bank
facilities and other sources. Short-term capital is required to finance accounts
receivable and other similar short-term assets, while the acquisition and
development of oil and natural gas properties requires larger amounts of
long-term capital.
At March 31, 2014, the Company had a $28 million extendible committed term bank
facility with a Canadian bank under which $27.9 million of credit was available
with $0.1 million in letters of credit outstanding that reduce the amount of
available credit. Under the agreement, advances can be drawn in Canadian funds
and bear interest at the bank's prime lending rate or guaranteed notes discount
rates plus applicable margins. These margins vary from 2.25% to 3.6% depending
on the borrowing option used.
Anderson will prudently use its bank loan facility to finance its operations as
required.
Loans are secured by general security agreements providing security interests
over all assets and by guarantees of material subsidiaries.
Under the terms of the bank facility, the Company has provided a financial
covenant that the amount of its current liabilities shall not exceed the sum of
its current assets and the undrawn availability under the facility at the end of
each fiscal quarter. Unrealized gains (losses) on derivative contracts are
excluded from the above amounts. The Company was in compliance with this
financial covenant as at March 31, 2014.
Subsequent to March 31, 2014, the Company agreed to an increase in its bank
facility from $28 million to $31 million, subject to customary closing
conditions. The term date was extended to May 30, 2015. If this revolving
operating loan facility is not extended at May 30, 2015, any outstanding
advances would become repayable one year later on May 30, 2016.
As of today's date, the Company is not drawn on its bank facility.
OFF-BALANCE SHEET ARRANGEMENTS
The Company had no guarantees or off-balance sheet arrangements other than as
described either below or in the management's discussion and analysis for the
year ended December 31, 2013 under "Contractual Obligations."
CONTRACTUAL OBLIGATIONS
The Company enters into various contractual obligations in the course of
conducting its operations. There were no material changes to the contractual
obligations that were discussed in management's discussion and analysis for the
year ended December 31, 2013 other than the following:
-- Cardium Horizontal Well Program (Oil) - At March 31, 2014, the Company
had an obligation under a farm-in agreement to drill one Cardium oil
well prior to October 31, 2014 to earn a working interest in the farm-
out lands. The capital commitment associated with the well is $2.5
million.
-- Office Lease - Subsequent to March 31, 2014, the Company entered into an
agreement to lease office space at a cost of approximately $0.4 million
per year from July 1, 2014 to October 30, 2018, subject to customary
closing conditions.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to make estimates,
assumptions and judgements in the application of IFRS that have a significant
impact on the financial results of the Company. Actual results could differ from
estimated amounts, and those differences may be material. A comprehensive
discussion of the Company's significant critical accounting estimates is
contained in the MD&A and the audited consolidated financial statements for the
year ended December 31, 2013.
NEW AND PENDING ACCOUNTING STANDARDS
Standards that are issued and that the Company reasonably expects to be
applicable at a future date are listed below.
IFRS 9 Financial Instruments. In November 2009, the IASB issued IFRS 9,
Financial Instruments ("IFRS 9 (2009)"), and in October 2010, the IASB published
amendments to IFRS 9 ("IFRS 9 (2010)"). In November 2013, the IASB issued a new
general hedge accounting standard, which forms part of IFRS 9 Financial
Instruments ("IFRS 9 (2013)").
IFRS 9 (2013) includes a new general hedge accounting standard which will align
hedge accounting more closely with risk management. This new standard does not
fundamentally change the types of hedging relationships or the requirement to
measure and recognize ineffectiveness; however, it will provide more hedging
strategies that are used for risk management to qualify for hedge accounting and
introduce more judgment to assess the effectiveness of a hedging relationship.
The amendments to IFRS 9 are applied retrospectively for annual periods
beginning on or after January 1, 2018, with early adoption allowed. The Company
is currently assessing the effect on its financial statements.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2014, the Company adopted the following new IFRS standards and
amendments in accordance with the transitional provisions of each standard. The
adoption of these standards did not have a material impact on the Company's
financial statements. A brief description of each new standard follows below:
i. Offsetting Financial Assets and Financial Liabilities (Amendments to IAS
32 Financial Instruments: Presentation ("IAS 32"). The amendments to IAS
32 clarify the requirements for offsetting financial instruments such as
the accounts receivable and payable related to the Company's commodity
contracts. The amendments clarify when an entity has a legally
enforceable right to offset and certain other requirements that are
necessary to present a net financial asset or liability.
ii. Levies ("IFRIC 21"). In May 2013, the International Accounting Standards
Board ("IASB") issued IFRIC 21 Levies which was developed by the IFRS
Interpretations Committee ("IFRIC"). IFRIC 21 clarifies that an entity
recognizes a liability for a levy when the activity that triggers
payment, as identified by the relevant legislation, occurs. The
interpretation also clarifies that no liability should be recognized
before the specified minimum threshold to trigger that levy is reached.
CONTROLS AND PROCEDURES
The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have
designed, or caused to be designed under their supervision, disclosure controls
and procedures ("DC&P") and internal controls over financial reporting ("ICOFR")
as defined in National Instrument 52-109 Certification of Disclosure in Issuer's
Annual and Interim Filings in order to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of the financial
statements for external purposes in accordance with IFRS.
The DC&P have been designed to provide reasonable assurance that material
information relating to the Company is made known to the CEO and CFO by others
and that information required to be disclosed by the Company in its annual
filings, interim filings or other reports filed or submitted by the Company
under securities legislation is recorded, processed, summarized and reported
within the time periods specified in securities legislation.
The CEO and CFO are required to cause the Company to disclose any change in the
Company's ICOFR that occurred during the period beginning on January 1, 2014 and
ending on March 31, 2014 that has materially affected, or is reasonably likely
to materially affect, the Company's ICOFR. No changes in ICOFR were identified
during such period that have materially affected or are reasonably likely to
materially affect the Company's ICOFR.
It should be noted that a control system, including the Company's DC&P and
ICOFR, no matter how well conceived or operated, can provide only reasonable,
not absolute, assurance that the objective of the control system will be met and
it should not be expected that DC&P and ICOFR will prevent all errors or fraud.
BUSINESS RISKS
Oil and gas exploration and production is capital intensive and involves a
number of business risks including, without limitation, the uncertainty of
finding new reserves, the instability of commodity prices, weather and various
operational risks. Commodity prices are influenced by local and worldwide supply
and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar
exchange rate, transportation costs, political stability and seasonal and
weather related changes to demand. The price of natural gas has recently
strengthened due to weather-related changes to demand; however, the concern over
increasing U.S. gas production, driven primarily by the U.S. shale gas plays,
continues to depress the natural gas futures market. Oil prices continue to
remain volatile as they are a geopolitical commodity, affected by concerns about
global economic markets and continued instability in oil producing countries.
Differentials between WTI oil prices and prices received in Alberta are
volatile. The industry is subject to extensive governmental regulation with
respect to the environment. Operational risks include well performance,
uncertainties inherent in estimating reserves, timing of/ability to obtain and
maintain drilling licences and other regulatory approvals, ability to obtain
equipment, expiration of licences and leases, competition from other producers,
third-party transportation and processing disruption issues, sufficiency of
insurance, ability to manage growth, reliance on key personnel, third party
credit risk and appropriateness of accounting estimates. These risks are
described in more detail in the Company's most recent Annual Information Form
filed with certain Canadian securities regulatory authorities on SEDAR at
www.sedar.com.
The Company makes substantial capital expenditures for the acquisition,
exploration, development and production of oil and natural gas reserves. As the
Company's revenues may decline as a result of decreased commodity pricing, it
may be required to reduce capital expenditures. In addition, uncertain levels of
near-term industry activity coupled with the present global economic concerns
exposes the Company to additional access to capital risk. There can be no
assurance that debt or equity financing, or funds generated by operations, will
be available or sufficient to meet these requirements or for other corporate
purposes or, if debt or equity financing is available, that it will be on terms
acceptable to the Company. The inability of the Company to access sufficient
capital for its operations could have a material adverse effect on the Company's
business, financial condition, results of operations and prospects.
Anderson manages these risks by employing competent and professional staff,
following sound operating practices and using capital prudently. The Company
generates its exploration and development prospects internally and performs
extensive geological, geophysical, engineering, and environmental analysis
before committing to the drilling of new prospects. Anderson seeks out and
employs new technologies where possible. With the Company's extensive drilling
inventory and advance planning, the Company believes it can manage the slower
pace of regulatory approvals and the requirements for extensive landowner
consultation.
The Company has a formal emergency response plan which details the procedures
employees and contractors will follow in the event of an operational emergency.
The emergency response plan is designed to respond to emergencies in an
organized and timely manner so that the safety of employees, contractors,
residents in the vicinity of field operations, the general public and the
environment are protected. A corporate safety program covers hazard
identification and control on the jobsite, establishes Company policies, rules
and work procedures and outlines training requirements for employees and
contract personnel.
The Company currently deals with a small number of buyers and sales contracts,
and endeavours to ensure that those buyers are an appropriate credit risk. The
Company continuously evaluates the merits of entering into fixed price or
financial hedge contracts for price management.
The oil and natural gas business is subject to regulation and intervention by
governments in such matters as the awarding of exploration and production
interests, the imposition of specific drilling obligations, environmental
protection controls, control over the development and abandonment of fields
(including restrictions on production) and possibly expropriation or
cancellation of contract rights. As well, governments may regulate or intervene
with respect to prices, taxes, royalties, transportation and the exportation of
oil and natural gas. Such regulation may be changed from time to time in
response to economic or political conditions. The implementation of new
regulations or the modification of existing regulations affecting the oil and
natural gas industry could reduce demand for oil and natural gas, increase the
Company's costs, impact the Company's ability to get its product to market, or
affect its future opportunities.
The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation. Such
legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and gas
industry operations. Such legislation may also impose restrictions and
prohibitions on water use or processing in connection with certain oil and gas
operations. In addition, such legislation requires that well and facility sites
be abandoned and reclaimed to the satisfaction of provincial authorities.
Compliance with such legislation can require significant expenditures and a
breach of such requirements may result in, amongst other things, suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and penalties.
STRATEGY
The Company's business plan is to pursue growth of its asset base and cash flow,
and increase its financial flexibility to meet its obligations when they become
due. Coming out of the strategic alternatives process, the Company is smaller in
terms of production, has cash in the bank and an unused bank operating line. Its
convertible debentures mature in 2016 and 2017.
With the bank debt issues resolved, Anderson intends to focus on rebuilding its
asset base by drilling Cardium and Mannville horizontal light oil wells, and
growing its Cardium and Mannville horizontal oil drilling inventory in the
Willesden Green, West Pembina and Buck Lake areas. In its first full quarter
since completion of the strategic alternatives process, the Company has shown
progress on all fronts, with increasing oil production, cash flow and reserves.
The longer-term debenture maturities give the Company time to rebuild its asset
base. By resuming a drilling program and controlling the infrastructure in its
Cardium oil properties where feasible, the Company should be able to increase
oil production and operating netbacks. A strategy of increasing oil assets,
production and cash flow should also support a higher borrowing base over time.
Anderson will continue to focus on reducing average well payouts. The goal is to
have Cardium wells pay out in approximately one year, on average, by continuing
to improve the profitability of these operations. The Company believes this goal
can be achieved by continuing to implement new approaches in Cardium horizontal
drilling and completion technologies, and by keeping costs as low as possible.
Recent technological changes include repositioning the trajectory of the
horizontal well within the Cardium zone to maximize frac effectiveness, and
using dissolvable frac balls. In 2014, the Company plans to drill its first
long-reach horizontal oil well that is expected to traverse up to 3,000 metres
of horizontal Cardium net pay. It is anticipated that long-reach horizontal
wells will access Cardium reserves in two sections of land as opposed to the
current one section of land per horizontal well. There is a capital cost benefit
to drilling an extended reach well over two sections as compared to two wells
traversing one section of land each. There is also a reserves benefit with
longer horizontal wells due to additional reservoir contact.
Where it can, the Company strives to operate its own oil and gas infrastructure
and attract third parties to utilize this infrastructure on a processing fee
basis in order to reduce overall operating costs. Currently, the Company
operates over 90% of its production and all of its current drilling operations.
Anderson is developing new light oil horizontal plays on its existing acreage in
the Mannville and Belly River and is planning to drill one of these plays in
2014.
The Company currently has no plans to dispose of its Cardium oil assets. In
addition, the Company currently has no plans to buy back common shares or
convertible debentures with normal course issuer bids. The Company's plan is to
continue to grow its asset base by investing in its light oil drilling
opportunities,
Anderson will continue to look for ways to optimize, rationalize, consolidate
and improve the profitability of its shallow gas business. In the fourth quarter
of 2013 and the first quarter of 2014, the Company disposed of unprofitable
shallow gas assets. The Company's remaining shallow gas properties are
profitable at current natural gas prices. The Company is not planning any
significant new investments in the shallow gas business, and may dispose of some
or all of its remaining shallow gas assets.
For 2014, the Company estimates that oil and NGL production will be
approximately 36% of total production, and that revenue from oil and NGL will be
approximately 66% of total revenue. The Company expects the percentage
contribution of oil and NGL to total revenue to grow, and estimates that its
production will be balanced between natural gas, and oil and NGL by the end of
2015.
2014 CAPITAL BUDGET
The Board of Directors has approved a 2014 capital budget of $46 million.
Sixty-eight percent of the budget is directed at drilling and completion
expenditures to drill 12 net Cardium and Mannville horizontal light oil drilling
prospects. Twenty-four percent of the expenditures are directed at equipping,
tie-in and facility expenditures and the remaining funds are directed at land,
abandonments and capitalized G&A expenditures.
With this capital program, the annual production guidance for 2014 has increased
to approximately 3,200 BOED (36% oil and NGL) up from the guidance provided by
Company in its March 31, 2014 press release (2,600 BOED, 33% oil and NGL). The
Company estimates 2014 exit production to be approximately 3,700 BOED (42% oil
and NGL).
In addition to the seven well 2013/2014 Cardium winter program, the Company is
planning to drill 15 gross (12.6 net) Cardium and Mannville light oil horizontal
wells from the second quarter of 2014 to spring breakup 2015. The Company
continues to evaluate farm-in and property acquisitions in its Cardium and
Mannville light oil focus areas. Should the Company add additional farm-in
commitments, it will substitute those commitments into its 2014 capital program
and defer budgeted locations until 2015.
QUARTERLY INFORMATION
The following table provides financial and operating results for the last eight
quarters. Commodity prices remained volatile, affecting funds from operations
and earnings throughout those quarters. The Company curtailed its drilling
program in 2012, drilling a modest number of wells in 4 of the past 8 quarters,
as shown in the following table:
Quarter Gross wells Net wells - capital Net wells - revenue
Q1 2014 4 4.0 4.0
Q4 2013 3 3.0 3.0
Q1 2013 2 1.8 1.5
Q4 2012 4 4.0 2.8
The impact of the sale of properties in 2012 and in the last quarter of 2013, as
well as natural production declines, contributed to lower production volumes and
revenues in 2012 and 2013. Production improved significantly in the first
quarter of 2014 relative to the last quarter of 2013 due to the Cardium
horizontal well winter drilling program during the last quarter of 2013 and the
first quarter of 2014.
Earnings were affected in the second quarter of 2012 by impairments in the value
of natural gas properties, whereas earnings in the second quarter of 2013 were
affected by the tax expense related to derecognizing the deferred tax asset.
Earnings in the third quarter of 2013 were impacted by the impairment on the
assets held for sale.
Bank loan balances fluctuated in response to the capital spending programs
related to Cardium oil development through 2012 and into 2013. Bank loans were
reduced by the proceeds from the sale of assets and from cash from operating
activities in 2012 and 2013.
SELECTED QUARTERLY INFORMATION
($ amounts in thousands,
except per share
amounts and prices) Q1 2014 Q4 2013 Q3 2013 Q2 2013
----------------------------------------------------------------------------
Revenue, net of
royalties $ 13,195 $ 7,288 $ 11,949 $ 14,345
Funds from operations(1) $ 5,538 $ (306) $ 1,408 $ 4,701
Funds from operations
per share, basic and
diluted(1) $ 0.03 $ - $ 0.01 $ 0.03
Adjusted earnings (loss)
before taxes(2) $ 544 $ (2,745) $ (5,856) $ (3,672)
Adjusted earnings (loss)
before taxes per share,
basic and diluted(2) $ - $ (0.02) $ (0.03) $ (0.02)
Earnings (loss) $ 544 $ (2,445) $ (48,737) $ (49,306)
Earnings (loss) per
share, basic and
diluted $ - $ (0.01) $ (0.28) $ (0.29)
Capital expenditures
(net of proceeds on
dispositions) $ 16,032 $ (71,972) $ 229 $ 186
Cash from operating
activities $ 2,375 $ (230) $ 1,626 $ 3,953
Bank loans $ - $ - $ 53,945 $ 53,892
Daily sales
Oil (bpd) 969 537 983 1,199
NGL (bpd) 170 166 280 297
Natural gas (Mcfd) 10,920 10,467 13,119 14,611
BOE (BOED) 2,958 2,448 3,449 3,931
Average prices
Oil ($/bbl)(4) $ 97.36 $ 84.26 $ 100.81 $ 89.76
NGL ($/bbl) $ 69.13 $ 61.60 $ 52.97 $ 48.73
Natural gas ($/Mcf)(4) $ 5.01 $ 3.19 $ 2.27 $ 3.33
BOE ($/BOE)(3)(4) $ 54.54 $ 36.49 $ 41.87 $ 43.66
----------------------------------------------------------------------------
Q1 2013 Q4 2012 Q3 2012 Q2 2012
----------------------------------------------------------------------------
Revenue, net of
royalties $ 15,268 13,796 $ 15,284 $ 18,290
Funds from operations(1) $ 5,486 5,694 $ 5,725 $ 7,606
Funds from operations
per share, basic and
diluted(1) $ 0.03 0.03 $ 0.03 $ 0.04
Adjusted earnings (loss)
before taxes(2) $ (5,113) (11,799) $ 173 $ (2,369)
Adjusted earnings (loss)
before taxes per share,
basic and diluted(2) $ (0.03) (0.07) $ - $ (0.01)
Earnings (loss) $ (5,113) (8,895) $ 94 $ (16,828)
Earnings (loss) per
share, basic and
diluted $ (0.03) (0.05) $ - $ (0.10)
Capital expenditures
(net of proceeds on
dispositions) $ 7,662 (26,880) $ (28,986) $ 4,786
Cash from operating
activities $ 5,171 6,976 $ 5,845 $ 7,712
Bank loans $ 55,141 48,094 $ 88,922 $ 119,686
Daily sales
Oil (bpd) 1,529 1,135 1,274 1,669
NGL (bpd) 203 338 576 750
Natural gas (Mcfd) 14,759 18,159 23,519 26,438
BOE (BOED) 4,191 4,500 5,770 6,825
Average prices
Oil ($/bbl)(4) $ 84.83 79.73 $ 80.44 $ 81.58
NGL ($/bbl) $ 61.77 52.02 $ 51.59 $ 54.38
Natural gas ($/Mcf) $ 2.94 3.16 $ 2.24 $ 1.72
BOE ($/BOE)(3)(4) $ 44.70 36.89 $ 32.05 $ 32.70
----------------------------------------------------------------------------
1. Funds from operations and funds from operations per share do not have
standardized meanings prescribed by GAAP. Refer to the sections entitled
"Funds from Operations" and "Additional GAAP Measures" at the end of
this MD&A.
2. Adjusted earnings (loss) before taxes, adjusted earnings (loss) before
taxes per share and operating netback per BOE are considered non-GAAP
measures. Refer to the section entitled "Non-GAAP Measures" at the end
of this MD&A.
3. Includes royalty and other income classified with oil and gas sales.
4. Excludes realized and unrealized hedging gains (losses) on derivative
contracts as follows: Q1 2014 - ($0.4 million) and ($0.5 million),
respectively; Q4 2013 - ($0.9 million) and $0.9 million, respectively;
Q3 2013 - $(1.6 million) and $0.5 million, respectively; Q2 2013 - ($0.7
million) and $0.6 million, respectively; Q1 2013 - ($0.6 million) and
($1.1 million), respectively; Q4 2012 - $2.2 million and ($2.8 million),
respectively; Q3 2012 - $1.7 million and ($2.7 million), respectively;
and Q2 2012 - $1.3 million and $4.7 million, respectively.
CONVERSION MEASURES
Production volumes and reserves are commonly expressed on a BOE basis whereby
natural gas volumes are converted at the ratio of 6 thousand cubic feet to 1
barrel of oil. Although the intention is to sum oil and natural gas measurement
units into one basis for improved analysis of results and comparisons with other
industry participants, BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 Mcf to 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. In recent years, the value
ratio based on the price of crude oil as compared to natural gas has been
significantly higher than the energy equivalency of 6:1, and utilizing a
conversion of natural gas volumes on a 6:1 basis may be misleading as an
indication of value.
NON-GAAP MEASURES
Included in this document are references to the terms "adjusted earnings (loss)
before taxes," "adjusted earnings (loss) before taxes per share," "operating
netback," "operating netback per share" and "general and administrative (cash)
expenses". Management believes these measures are helpful supplementary measures
of financial performance and provide users with information that is commonly
used by other oil and gas companies. These terms do not have any standardized
meaning prescribed by GAAP and should not be considered an alternative to, or
more meaningful than, "earnings (loss) before taxes" or "earnings (loss) and
comprehensive income (loss)" as determined in accordance with GAAP as a measure
of the Company's performance.
Adjusted earnings (loss) before taxes is calculated as earnings (loss) before
taxes per the Consolidated Statement of Operations and Comprehensive Income
(Loss), excluding impairment loss, and provides supplemental information on the
Company's before income tax performance, excluding the impact of impairment
losses. Operating netback is calculated as oil and gas sales plus applicable
realized gains/losses on derivative contracts less royalties, operating expenses
and transportation expenses and is a measure of the profitability of operations
before administrative, financing and other non-cash items.
General and administrative (cash) expenses are general and administrative costs
excluding non-cash share-based compensation and provides supplemental
information regarding the impact of general and administrative costs on the
Company's cash flows.
ADDITIONAL GAAP MEASURES
Funds from operations
This document, including the accompanying financial statements, contain the term
"funds from operations" which does not have any standardized meaning prescribed
by GAAP and should not be considered an alternative to, or more meaningful than,
"cash flow from operating activities" as determined in accordance with GAAP as a
measure of the Company's performance. Funds from operations or funds from
operations per share may not be comparable with the calculation of similar
measures for other entities. Funds from operations as used in this report
represent cash from operating activities before changes in non-cash working
capital and decommissioning expenditures. See "Funds from Operations" under
"Review of Financial Results" for details of this calculation. Management
believes that funds from operations represent both an indicator of the Company's
performance and a funding source for ongoing operations.
Other additional GAAP measures
This document including the accompanying financial statements also contain the
terms "working capital or working capital (deficiency)," "net debt before
convertible debentures," "total net debt" and "total capitalization" which do
not have any standardized meaning prescribed by GAAP and may not be comparable
with the calculation of similar measures for other entities.
Working capital is defined as the difference between current assets and current
liabilities. Working capital (deficiency) is the term used when the difference
between current assets and current liabilities is a negative number. The
unrealized gains on derivative contracts are excluded from current assets and
unrealized losses on derivative contracts are excluded from current liabilities
in the calculation of working capital and working capital (deficiency). Working
capital and working capital (deficiency) represent operating liquidity available
to the business and are included in the definition of the additional GAAP term
"net debt."
Net debt before convertible debentures is calculated as long-term debt plus
working capital or working capital (deficiency). Total net debt is calculated as
net debt before convertible debentures plus the liability component of
convertible debentures. Management believes these measures are useful
supplementary measures of the total amount of current and long-term debt. Total
capitalization is calculated as total net debt plus shareholders' equity.
Management believes this measure is a useful supplementary measure of the
Company's managed capital.
FORWARD-LOOKING STATEMENTS
Certain statements in this news release including, without limitation,
management's assessment of future plans and operations; benefits and valuation
of the development prospects described herein; number of locations in drilling
inventory and wells to be drilled; timing and location of drilling and tie-in of
wells and the costs thereof; productive capacity of the wells; timing and
construction of facilities; expected production rates; improved production from
slick water fracture technology; percentage of production from oil and natural
gas liquids; dates of commencement of production; amount of capital expenditures
and the timing and method of financing thereof; value of undeveloped land;
extent of reserves additions; ability to attain cost savings; drilling program
success; impact of changes in commodity prices on operating results;
expectations related to future operating netbacks; programs to optimize,
rationalize, consolidate and improve profitability of assets; factors on which
the continued development of the Company's oil and gas assets are dependent;
commodity price outlook; and general economic outlook may constitute
"forward-looking information" within the meaning of applicable securities laws
and necessarily involve risks and assumptions made by management of the Company
including, without limitation, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation; loss of
markets; volatility of commodity prices; currency fluctuations; imprecision of
reserves estimates; environmental risks; competition from other producers;
inability to retain drilling rigs and other services; adequate weather to
conduct operations; sufficiency of budgeted capital, operating and other costs
to carry out planned activities; wells not performing as expected; incorrect
assessment of the value of acquisitions and farm-ins; failure to realize the
anticipated benefits of acquisitions and farm-ins; inability to complete
property dispositions or to complete them at anticipated values; delays
resulting from or inability to obtain required regulatory approvals; changes to
government regulation; ability to access sufficient capital from internal and
external sources; and other factors, many of which are beyond the Company's
control.
The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as the factors are
interdependent, and management's future course of action would depend on its
assessment of all information at the time. As a consequence, actual results may
differ materially from those anticipated in the forward-looking statements and
readers should not place undue reliance on the assumptions and forward-looking
statements. Readers are cautioned that the foregoing list of factors is not
exhaustive. Additional information on these and other factors that could affect
Anderson's operations and financial results are included in reports on file with
Canadian securities regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com) or at Anderson's website (www.andersonenergy.ca).
The forward-looking statements contained in this news release are made as at the
date of this news release and the Company does not undertake any obligation to
update publicly or to revise any of the included forward-looking statements,
whether as a result of new information, future events or otherwise, except as
may be required by applicable securities laws.
ANDERSON ENERGY LTD.
Consolidated Statements of Financial Position
(Stated in thousands of dollars) March 31, December 31,
(Unaudited) 2014 2013
----------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 12,364 $ 25,111
Accounts receivables and accruals 10,228 6,702
Prepaid expenses and deposits 941 1,286
---------------------------------------------------------------------------
Total current assets 23,533 33,099
Deferred tax asset 2,000 2,000
Property, plant and equipment (note 3) 145,014 135,978
---------------------------------------------------------------------------
Total assets $ 170,547 $ 171,077
---------------------------------------------------------------------------
---------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accruals $ 24,526 $ 23,417
Unrealized loss on derivative contracts
(note 11) 610 146
---------------------------------------------------------------------------
Total current liabilities 25,136 23,563
Convertible debentures 89,517 88,922
Decommissioning obligations (note 5) 27,054 30,413
---------------------------------------------------------------------------
Total liabilities 141,707 142,898
Shareholders' equity:
Share capital (note 6) 171,460 171,460
Equity component of convertible debentures 5,019 5,019
Contributed surplus 11,355 11,238
Deficit (158,994) (159,538)
----------------------------------------------------------------------------
Total shareholders' equity 28,840 28,179
Commitments and contingencies (note 12)
Subsequent events (notes 4, 11, 12)
---------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 170,547 $ 171,077
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Income (Loss)
THREE MONTHS ENDED MARCH 31, 2014 AND 2013
(Stated in thousands of dollars, except per share
amounts)
(Unaudited) 2014 2013
---------------------------------------------------------------------------
Oil and gas sales $ 14,522 $ 16,863
Royalties (1,327) (1,595)
---------------------------------------------------------------------------
Revenue, net of royalties 13,195 15,268
Other losses (note 8) (871) (1,657)
---------------------------------------------------------------------------
Total revenue, net of royalties and other losses 12,324 13,611
Operating expenses 3,536 4,503
Transportation expenses 62 77
Depletion and depreciation (note 3) 5,653 8,613
(Gain) loss on sale of property, plant and equipment
(note 3) (1,992) 6
General and administrative expenses 1,941 2,252
---------------------------------------------------------------------------
Earnings (loss) from operating activities 3,124 (1,840)
Finance income (note 9) 59 1
Finance expenses (note 9) (2,639) (3,274)
---------------------------------------------------------------------------
Net finance expenses (2,580) (3,273)
---------------------------------------------------------------------------
Earnings (loss) and comprehensive income (loss) for
the period 544 (5,113)
---------------------------------------------------------------------------
Basic and diluted earnings (loss) per share (note 7) $ - $ (0.03)
----------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Changes in Shareholders' Equity
THREE MONTHS ENDED MARCH 31, 2014 AND 2013
(Stated in thousands of dollars, except number of common shares)
(Unaudited)
Equity component
Number of common Share of convertible
shares capital debentures
----------------------------------------------------------------------------
Balance at December 31, 2012 172,549,701 $ 171,460 $ 5,019
Share-based payments - - -
Loss for the period - - -
----------------------------------------------------------------------------
Balance at March 31, 2013 172,549,701 $ 171,460 $ 5,019
----------------------------------------------------------------------------
Balance at December 31, 2013 172,549,701 $ 171,460 $ 5,019
Share-based payments - - -
Earnings for the period - - -
----------------------------------------------------------------------------
Balance at March 31, 2014 172,549,701 $ 171,460 $ 5,019
----------------------------------------------------------------------------
Total
Contributed shareholders'
surplus Deficit equity
----------------------------------------------------------------------------
Balance at December 31, 2012 $ 10,418 $ (53,937) $ 132,960
Share-based payments 263 - 263
Loss for the period - (5,113) (5,113)
----------------------------------------------------------------------------
Balance at March 31, 2013 $ 10,681 $ (59,050) $ 128,110
----------------------------------------------------------------------------
Balance at December 31, 2013 $ 11,238 $ (159,538) $ 28,179
Share-based payments 117 - 117
Earnings for the period - 544 544
----------------------------------------------------------------------------
Balance at March 31, 2014 $ 11,355 $ (158,994) $ 28,840
----------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
THREE MONTHS ENDED MARCH 31, 2014 AND 2013
(Stated in thousands of dollars)
(Unaudited) 2014 2013
---------------------------------------------------------------------------
CASH PROVIDED BY (USED IN)
OPERATIONS
Earnings (loss) for the period $ 544 $ (5,113)
Adjustments for:
Unrealized loss on derivative contracts (note
8) 464 1,071
(Gain) loss on sale of property, plant and
equipment (note 3) (1,992) 6
Depletion and depreciation (note 3) 5,653 8,613
Share-based payments 82 197
Accretion on decommissioning obligations (note
5) 192 188
Accretion on convertible debentures (note 9) 595 524
Decommissioning expenditures (note 5) (181) (76)
Changes in non-cash working capital (note 10) (2,982) (239)
---------------------------------------------------------------------------
Net cash provided by operations 2,375 5,171
FINANCING
Increase in bank loans - 7,047
---------------------------------------------------------------------------
Net cash used in financing - 7,047
INVESTING
Property, plant and equipment expenditures (note
3) (16,082) (7,662)
Proceeds from sale of property, plant and
equipment (note 3) 50 -
Changes in non-cash working capital (note 10) 910 (4,557)
---------------------------------------------------------------------------
Net cash used in investing (15,122) (12,219)
Decrease in cash and cash equivalents (12,747) (1)
Cash and cash equivalents, beginning of period 25,111 1
---------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 12,364 $ -
---------------------------------------------------------------------------
Interest received in cash $ 84 $ 1
Interest paid in cash $ (1,879) $ (2,565)
---------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial statements.
ANDERSON ENERGY LTD.
Notes to the Condensed Interim Consolidated Financial Statements
THREE MONTHS ENDED MARCH 31, 2014 WITH COMPARATIVE FIGURES FOR 2013
(Tabular amounts in thousands of dollars, unless otherwise stated)
(Unaudited)
1. REPORTING ENTITY
Anderson Energy Ltd. and its wholly-owned subsidiaries (collectively "Anderson"
or the "Company") are engaged in the acquisition, exploration and development of
oil and gas properties in western Canada. Anderson is a public company
incorporated and domiciled in Canada. Anderson's common shares and convertible
debentures are listed on the Toronto Stock Exchange. The Company's registered
office and principal place of business is 2200, 333 - 7th Avenue SW, Calgary,
Alberta, Canada, T2P 2Z1.
2. BASIS OF PREPARATION
(a) Statement of compliance:
The condensed interim consolidated financial statements comply with
International Accounting Standard 34 Interim Financial Reporting and do not
include all of the information required for full annual financial statements.
The condensed interim consolidated financial statements were authorized for
issuance by the Board of Directors on May 12, 2014.
(b) Accounting policies, judgments, estimates and disclosures:
In preparing these condensed interim consolidated financial statements, the
accounting policies, methods of computation and significant judgements made by
management in applying the Company's accounting policies and key sources of
estimation uncertainty were the same as those that applied to the audited
consolidated financial statements as at and for the years ended December 31,
2013 and 2012 except as disclosed below.
On January 1, 2014, the Company adopted new standards with respect to Offsetting
Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial
Instruments: Presentation ("IAS 32") and IFRIC 21 Levies ("IFRIC 21"). The
amendments to IAS 32 clarify the requirements for offsetting financial
instruments such as the amounts receivable and payable related to the Company's
commodity contracts. The amendments clarify when an entity has a legally
enforceable right to offset and certain other requirements that are necessary to
present a net financial asset or liability. IFRIC 21 clarifies that an entity
recognizes a liability for a levy when the activity that triggers payment, as
identified by the relevant legislation, occurs. The interpretation also
clarifies that no liability should be recognized before the specified minimum
threshold to trigger that levy is reached. The adoption of these standards had
no impact on the amounts recorded in the consolidated financial statements as at
January 1, 2014 or on the comparative periods.
The following disclosures are incremental to those included with the annual
audited consolidated financial statements. Certain disclosures that are normally
required in the notes to the annual audited consolidated financial statements
have been condensed or omitted. These condensed interim consolidated financial
statements should be read in conjunction with the Company's audited consolidated
financial statements and notes thereto for the years ended December 31, 2013 and
2012.
3. PROPERTY, PLANT AND EQUIPMENT
Cost or deemed cost
Oil and
natural Other
gas assets equipment Total
----------------------------------------------------------------------------
Balance at December 31, 2012 $ 593,048 $ 1,904 $ 594,952
Additions 8,128 17 8,145
Disposals (204,757) - (204,757)
----------------------------------------------------------------------------
Balance at December 31, 2013 396,419 1,921 398,340
Additions 15,837 11 15,848
Disposals (9,580) - (9,580)
----------------------------------------------------------------------------
Balance at March 31, 2014 $ 402,676 $ 1,932 $ 404,608
----------------------------------------------------------------------------
Accumulated depletion, depreciation and impairment losses
Oil and
natural
gas Other
assets equipment Total
----------------------------------------------------------------------------
Balance at December 31, 2012 $ 307,251 $ 1,527 $ 308,778
Depletion and depreciation for the
year 27,805 104 27,909
Impairment loss 44,581 - 44,581
Disposals (118,906) - (118,906)
----------------------------------------------------------------------------
Balance at December 31, 2013 $ 260,731 $ 1,631 $ 262,362
Depletion and depreciation for the
period 5,629 24 5,653
Disposals (8,421) - (8,421)
----------------------------------------------------------------------------
Balance at March 31, 2014 $ 257,939 $ 1,655 $ 259,594
----------------------------------------------------------------------------
Carrying amounts
Oil and
natural Other
gas assets equipment Total
----------------------------------------------------------------------------
At December 31, 2013 $ 135,688 $ 290 $ 135,978
At March 31, 2014 $ 144,737 $ 277 $ 145,014
----------------------------------------------------------------------------
Capitalized overhead
For the three months ended March 31, 2014, additions to property, plant and
equipment included internal overhead costs of $0.5 million (year ended December
31, 2013 - $1.8 million).
Sale of property, plant and equipment
For the three months ended March 31, 2014, the Company sold interests in
properties for total consideration of $0.1 million (year ended December 31, 2013
- $80.1 million). Provisions for decommissioning obligations related to assets
sold were $3.1 million. A gain on sale of assets of $2.0 million was recorded
for the three months ended March 31, 2014.
4. BANK LOANS
At March 31, 2014, the Company has a $28 million extendible committed term bank
facility with a Canadian bank. Under the agreement, advances can be drawn in
Canadian funds and bear interest at the bank's prime lending rate or guaranteed
notes discount rates plus applicable margins. These margins vary from 2.25% to
3.6% depending on the borrowing option used.
The Company had no operating loans outstanding during the three months ended
March 31, 2014. The average effective interest rate on advances under the
Company's operating loan facilities during the three months ended March 31, 2013
was 5.5%. The Company had $0.1 million in letters of credit outstanding at March
31, 2014 that reduce the amount of credit available to the Company.
Loans are secured by general security agreements providing security interests
over all assets and by guarantees of material subsidiaries.
Under the terms of the bank facility, the Company has provided a financial
covenant that the amount of its current liabilities shall not exceed the sum of
its current assets and the undrawn availability under the facility at the end of
each fiscal quarter. Unrealized gains (losses) on derivative contracts and the
current portion of any bank debt, convertible debentures and capital leases, if
any, are excluded from the above amounts.
Subsequent to March 31, 2014, the Company agreed to an increase its bank
facility from $28 million to $31 million, subject to the completion of customary
closing conditions. The term date was extended to May 30, 2015. If this
revolving operating loan facility is not extended at May 30, 2015, any
outstanding advances would become repayable one year later on May 30, 2016.
5. DECOMMISSIONING OBLIGATIONS
March 31, 2014 December 31, 2013
---------------------------------------------------------------------------
Balance at January 1 $ 30,413 $ 46,467
Provisions incurred 363 438
Total abandonment expenditures (181) (971)
Provisions disposed (3,126) (7,865)
Change in estimates (607) (8,470)
Accretion expense 192 814
---------------------------------------------------------------------------
Ending balance $ 27,054 $ 30,413
---------------------------------------------------------------------------
The Company's decommissioning obligations result from its ownership interest in
oil and natural gas assets including well sites and gathering systems. The
Company has estimated the net present value of the decommissioning obligations
to be $27.1 million as at March 31, 2014 (December 31, 2013 - $30.4 million)
based on an undiscounted inflation-adjusted total future liability of $48.5
million (December 31, 2013 - $49.9 million). These payments are expected to be
made over the next 30 years with the majority of costs to be incurred between
2016 and 2029. At March 31, 2014, the liability has been calculated using an
inflation rate of 2.0% (December 31, 2012 - 2.0%) and discounted using a
risk-free rate of 1.0% to 3.3% (December 31, 2013 - 1.1% to 3.2%) depending on
the estimated timing of the future obligation.
6. SHARE CAPITAL
Authorized share capital:
The Company is authorized to issue an unlimited number of common and preferred
shares. The preferred shares may be issued in one or more series.
Issued share capital:
Number of
Common
Shares Amount
----------------------------------------------------------------------------
Balance at December 31, 2012, December 31, 2013
and March 31, 2014 172,549,701 $ 171,460
----------------------------------------------------------------------------
Stock options:
The Company has an employee stock option plan under which employees, directors
and consultants are eligible to purchase common shares of the Company. Options
are granted using an exercise price of stock options equal to the weighted
average trading price of the Company's common shares for the five trading days
prior to the date of the grant. Options have terms of either five or 10 years
and vest equally over a two or three year period starting on the first
anniversary date of the grant.
Changes in the number of options outstanding during the period ended March 31,
2014 and the year ended December 31, 2013 are as follows:
March 31, 2014 December 31, 2013
----------------------------------------------------------------------------
Weighted Weighted
average average
Number of exercise Number of exercise
options price options price
----------------------------------------------------------------------------
Opening balance 15,413,350 $ 0.54 14,386,800 $ 0.75
Granted during the
period 15,600 0.14 3,160,100 0.13
Expired during the
period (116,000) 0.77 (1,295,617) 1.89
Forfeited during the
period (106,700) 0.26 (837,933) 0.49
----------------------------------------------------------------------------
Ending balance 15,206,250 $ 0.54 15,413,350 $ 0.54
----------------------------------------------------------------------------
Exercisable, end of
period 7,850,817 $ 0.79 7,951,817 $ 0.79
----------------------------------------------------------------------------
The range of exercise prices of the outstanding options is as follows:
Weighted Weighted
average average
exercise remaining
Range of exercise prices Number of options price life (years)
----------------------------------------------------------------------------
$0.13 to $0.20 3,127,000 $ 0.13 4.6
$0.21 to $0.32 5,027,300 0.31 3.6
$0.33 to $0.50 120,000 0.45 2.6
$0.51 to $0.77 2,379,600 0.70 2.4
$0.78 to $1.17 4,318,350 0.93 0.9
$1.18 to $1.77 141,000 1.21 1.7
$2.68 to $4.00 93,000 4.00 0.2
----------------------------------------------------------------------------
Total at March 31, 2014 15,206,250 $ 0. 54 2.8
----------------------------------------------------------------------------
There were no options exercised in the three months ended March 31 2014 and
March 31, 2013.
The fair value of the options was estimated using the Black-Scholes model with
the following weighted average inputs for the three months ended March 31, 2014
(there were no options issued during the three months ended March 31, 2013):
This estimated forfeiture rate is adjusted to the actual forfeiture rate when
each tranche vests. Share-based compensation of $0.1 million (March 31, 2013 -
$0.2 million) was expensed during the three months ended March 31, 2014. In
addition, share-based compensation of nil (March 31, 2013 - $0.1 million) was
capitalized during the three months ended March 31, 2014.
March 31, 2014
----------------------------------------------------------------------------
Fair value at grant date $ 0.08
Common share price $ 0.14
Exercise price $ 0.14
Volatility 67%
Option life 5 years
Dividends 0%
Risk-free interest rate 1.7%
Forfeiture rate 20%
----------------------------------------------------------------------------
7. EARNINGS (LOSS) PER SHARE
Basic and diluted earnings (loss) per share was calculated as follows:
March 31, March 31,
2014 2013
----------------------------------------------------------------------------
Earnings (loss) for the period $ 544 $ (5,113)
----------------------------------------------------------------------------
Weighted average number of common shares (basic),
(in thousands of shares) 172,550 172,550
----------------------------------------------------------------------------
Basic earnings (loss) per share $ - $ (0.03)
----------------------------------------------------------------------------
Weighted average number of common shares
(diluted), (in thousands of shares) 172,943 172,550
----------------------------------------------------------------------------
Diluted earnings (loss) per share $ - $ (0.03)
----------------------------------------------------------------------------
The average market value of the Company's common shares for purposes of
calculating the dilutive effect of stock options was based on quoted market
prices for the period that the options were outstanding. For the three months
ended March 31, 2014, 12,030,550 options (March 31, 2013 - 14,143,800 options)
and 59,316,889 common shares reserved for convertible debentures (March 31, 2013
- 59,316,889) were excluded from calculating dilutive earnings as they would not
have been dilutive.
8. OTHER LOSSES
Other losses include the following:
March 31, March 31,
2014 2013
----------------------------------------------------------------------------
Realized loss on derivative contracts $ (407) $ (586)
Unrealized loss on derivative contracts (464) (1,071)
----------------------------------------------------------------------------
$ (871) $ (1,657)
----------------------------------------------------------------------------
9. FINANCE INCOME AND EXPENSES
March 31, March 31,
2014 2013
----------------------------------------------------------------------------
Income:
Interest income on cash equivalents $ 55 $ 1
Other interest income 4 -
Expenses:
Interest and financing costs on bank loans (77) (768)
Interest on convertible debentures (1,771) (1,771)
Accretion on convertible debentures (595) (524)
Accretion on decommissioning obligations (note
5) (192) (188)
Other (4) (23)
----------------------------------------------------------------------------
Net finance expenses $ (2,580) $ (3,273)
----------------------------------------------------------------------------
10. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
March 31, March 31,
2014 2013
----------------------------------------------------------------------------
Source (use) of cash
Accounts receivable and accruals $ (3,526) $ (368)
Prepaid expenses and deposits 345 113
Accounts payable and accruals 1,109 (4,541)
----------------------------------------------------------------------------
$ (2,072) $ (4,796)
----------------------------------------------------------------------------
Related to operating activities $ (2,982) $ (239)
Related to financing activities $ - $ -
Related to investing activities $ 910 $ (4,557)
----------------------------------------------------------------------------
11. FINANCIAL RISK MANAGEMENT
The Company classified the fair value of its financial instruments measured at
fair value according to the following hierarchy based on the amount of
observable inputs used to value the instrument:
-- Level 1 - observable inputs such as quoted prices in active markets;
-- Level 2 - inputs, other than the quoted market prices in active markets,
which are observable, either directly and/or indirectly; and
-- Level 3 - unobservable inputs for the asset or liability in which little
or no market data exists, therefore requiring an entity to develop its
own assumptions.
The fair value of the derivative contracts used for risk management as shown in
the condensed interim consolidated financial statements as at March 31, 2014 and
the audited consolidated financial statements as at December 31, 2013 are
measured using level 2.
(a) Liquidity risk.
Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they fall due. The Company's objective is to ensure, as
far as possible, that it will always have sufficient liquidity to meet its
liabilities when due, under both normal and stressed conditions, without
incurring unacceptable losses or risking damage to the Company's reputation.
The following are the contractual maturities of financial liabilities, including
associated interest payments on convertible debentures and excluding the impact
of netting agreements at March 31, 2014:
Less Three
than One to Two to to Four to
one two three four five
Financial Liabilities year years years years years
----------------------------------------------------------------------------
Non-derivative financial
liabilities
Accounts payable and
accruals (1) $ 24,526 $ - $ - $ - $ -
Convertible debentures
- Interest (1) 5,626 7,085 3,335 1,667 -
- Principal - 50,000 - 46,000 -
----------------------------------------------------------------------------
Total $ 30,152 $ 57,085 $ 3,335 $ 47,667 $ -
----------------------------------------------------------------------------
1. Accounts payable and accruals includes $1.5 million of interest relating
to convertible debentures. The total cash interest payable in less than
one year on the convertible debentures is $7.1 million.
(b) Market risk.
Market risk is the risk that changes in market prices, such as commodity prices,
foreign exchange rates and interest rates that will affect the Company's
earnings or the value of the financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
parameters, while optimizing the return.
The Company may use both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted within
risk management tolerances that are reviewed by the Board of Directors.
Currency risk. Prices for oil are determined in global markets and generally
denominated in United States dollars. Natural gas prices are influenced by both
U.S. and Canadian supply and demand. The exchange rate effect cannot be
quantified, but generally an increase in the value of the Canadian dollar as
compared to the U.S. dollar will reduce the prices received by the Company for
its petroleum and natural gas sales.
There were no financial instruments denominated in U.S. dollars at March 31,
2014 or December 31, 2013.
Interest rate risk. Interest rate risk is the risk that future cash flows will
fluctuate as a result of changes in market interest rates. The interest charged
on the outstanding bank loans fluctuates with the interest rates posted by the
lenders. The Company has not entered into any mitigating interest rate hedges or
swaps, however the Company has $50 million and $46 million of convertible
debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing
January 31, 2016 and June 30, 2017. The Company had no loans outstanding during
the three months ended March 31, 2014.
Commodity price risk. Commodity price risk is the risk that the fair value or
future cash flows will fluctuate as a result of changes in commodity prices.
Commodity prices for oil and natural gas are impacted by both the relationship
between the Canadian and U.S. dollar and world economic events that dictate the
levels of supply and demand.
At March 31, 2014 the following derivative contracts were outstanding and
recorded at estimated fair value in the amount of $0.6 million:
Weighted
Average
Fixed
Type of Contract(1) Commodity Volume Price Remaining Period
----------------------------------------------------------------------------
Natural April 1, 2014 to
Financial swap gas 2,500 GJ/d $ 3.55/GJ December 31, 2014
----------------------------------------------------------------------------
1. Swap indicates fixed price payable to Anderson in exchange for floating
price payable to counterparty.
The fair value of derivative contracts at March 31, 2014 was determined using
quoted prices in active markets for natural gas, and would have been impacted as
follows had the natural gas prices used to estimate the fair value changed by:
Effect of an Effect of a decrease
increase in price on in price on after-
after-tax earnings tax earnings
----------------------------------------------------------------------------
Canadian $0.50 per GJ change
in the natural gas prices $ (258) $ 258
----------------------------------------------------------------------------
In December 2013, the Company entered into a physical sales contract to sell
2,500 GJ per day of natural gas between January 1, 2014 and December 31, 2014 at
a weighted average AECO price of $3.72 per GJ. This contract remained in effect
at March 31, 2014.
Subsequent to March 31, 2014 the Company entered into the following derivative
contract for crude oil:
Weighted average Weighted average WTI
Period volume (bpd) Canadian ($/bbl)
----------------------------------------------------------------------------
May 1, 2014 to December 31, 2014 500 $ 110.00
----------------------------------------------------------------------------
(c) Capital management.
Anderson's objective in managing its capital structure is to safeguard its
ability to meet its financial obligations and to fund the future development of
its business. The current capital management strategy is designed so that
anticipated cash flow from operating activities combined with available credit
facilities will fund continued oil and natural gas acquisition, exploration and
development activities to grow the value of its asset base for its shareholders.
The Company manages its capital structure and makes adjustments to it in the
light of changes in economic conditions, the risk characteristics of the
underlying assets and its growth opportunities. The Company's capital structure
includes working capital, bank loans, convertible debentures, and shareholders'
equity. In order to maintain or adjust the capital structure, the Company may,
at different times, adjust its capital spending, dispose of certain assets,
hedge future commodity prices, buy back convertible debentures or seek other
forms of debt or equity financing.
To assess capital and operating efficiency, the Company monitors its bank debt
level and working capital. It also monitors the ratio of bank debt and other
debt to funds from operations (defined as cash flow from operating activities
before changes in non-cash working capital and decommissioning expenditures).
The Company prepares annual operating and capital budgets, which are updated as
necessary depending on varying factors including current and forecast crude oil
and natural gas prices, capital deployment and general industry conditions. The
annual and updated budgets are approved by the Board of Directors. Anderson does
not pay dividends.
Anderson's current capital structure is summarized below:
March 31, December
2014 31, 2013
----------------------------------------------------------------------------
Current liabilities(1) $ 24,526 $ 23,417
Current assets(1) (23,533) (33,099)
----------------------------------------------------------------------------
Working capital deficit (surplus) $ 993 $ (9,682)
Bank loans - -
----------------------------------------------------------------------------
Net debt before convertible debentures 993 (9,682)
Convertible debentures (liability component)(2) 89,517 88,922
----------------------------------------------------------------------------
Total net debt $ 90,510 $ 79,240
Shareholders' equity 28,840 28,179
----------------------------------------------------------------------------
Total capitalization $ 119,350 $ 107,419
----------------------------------------------------------------------------
1. Excludes unrealized gains (losses) on derivative contracts.
2. Face value of convertible debentures: Series A Debentures $50 million,
Series B Debentures $46 million.
Funds from operations were $5.5 million for the three months ended March 31,
2014 (March 31, 2013 - $5.5 million.). Funds from operations are dependent on
many factors, including the success of oil and natural gas acquisition,
exploration and development activities, commodity prices including quality and
basis differentials, royalties, operating, administrative and financing costs,
and general market conditions.
Funds from operations, working capital, working capital deficiency, net debt
before convertible debentures, total net debt and total capitalization are not
defined by IFRS and therefore are referred to as additional GAAP measures.
The Company is subject to a financial covenant associated with its existing
credit facility. See note 4. The Company has complied with this financial
covenant for the three months ended March 31, 2014. The credit facility is
subject to an annual review of the borrowing base which is directly impacted by
the value of the oil and natural gas reserves.
12. COMMITMENTS AND CONTINGENCIES
At March 31, 2014, the Company had firm service gas transportation agreements in
which the Company guarantees that certain minimum volumes of natural gas will be
shipped on various gas transportation systems. The terms of the various
agreements expire in one to six years. If no volumes were shipped pursuant to
the agreements, the maximum amounts payable under the guarantees based on
current tariff rates are as follows:
2014 2015 2016 2017 2018 Thereafter
----------------------------------------------------------------------------
Firm service commitment $ 618 $ 757 $ 169 $ 137 $ 118 $ 136
----------------------------------------------------------------------------
Firm service committed volumes
(MMcfd) 4 5 4 3 3 3
----------------------------------------------------------------------------
There are no material changes to other commitments and contingencies from those
disclosed in the Company's annual audited consolidated financial statements as
at and for the years ended December 31, 2013 and 2012 other than as described
herein. At March 31, 2014, the Company had an obligation under a farm-in
agreement to drill one Cardium oil well prior to October 31, 2014 to earn a
working interest in the farm-out lands. The capital commitment associated with
the well is $2.5 million. Subsequent to March 31, 2014, the Company entered into
an agreement to lease office space at a cost of approximately $0.4 million per
year from July 1, 2014 to October 30, 2018, subject to customary closing
conditions.
Corporate Information
Auditors
Head Office
2200, 333 - 7th Avenue S.W. KPMG LLP
Calgary, Alberta
Canada T2P 2Z1 Independent Engineers
Phone (403) 262-6307
Fax (403) 261-2792 GLJ Petroleum Consultants Ltd.
Website
http://www.andersonenergy.ca/ Legal Counsel
Directors Bennett Jones LLP
J.C. Anderson Registrar and Transfer Agent
Calgary, Alberta
Valiant Trust Company
Brian H. Dau
Calgary, Alberta Stock Exchange
Christopher L. Fong (1)(2)(3) The Toronto Stock Exchange
Calgary, Alberta Symbol AXL, AXL.DB, AXL.DB.B
David J. Sandmeyer (1)(2)(3) Investor Relations Contact
Calgary, Alberta
Chairman of the Board Anderson Energy Ltd.
Brian H. Dau
David G. Scobie (1)(2)(3) President & Chief Executive Officer
Calgary, Alberta (403) 262-6307
info@andersonenergy.ca
Member of:
(1)Audit Committee Abbreviations
(2)Compensation and Corporate
Governance Committee bbl - barrel
(3)Reserves Committee bpd - barrels per day
BOE - barrels of oil equivalent
Officers BOED - barrels of oil equivalent per
day
Brian H. Dau BOPD - barrels of oil per day
President & Chief Executive Officer m3 - cubic meters
Mbbls - thousand barrels
David M. Spyker MBOE - thousand barrels of oil
Chief Operating Officer equivalent
MMBOE - million barrels of oil
M. Darlene Wong equivalent
Vice President, Finance, Mstb - thousand stock tank barrels
Chief Financial Officer & Corporate WTI - West Texas Intermediate
Secretary AECO - intra-Alberta Nova inventory
transfer price
Blaine M. Chicoine Bcf - billion cubic feet
Vice President, Drilling and GJ - gigajoule
Completions Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
Sandra M. Drinnan MMBtu - million British thermal units
Vice President, Land MMcf - million cubic feet
MMcfd - million cubic feet per day
Philip A. Harvey NGL - natural gas liquids
Vice President, Exploitation Cdn - Canadian
US - United States
Jamie A. Marshall
Vice President, Exploration
FOR FURTHER INFORMATION PLEASE CONTACT:
Investor Relations Contact
Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307
info@andersonenergy.ca
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