TWO GAME-CHANGING OIL PLAYS
BELIEVE IT
2012 ANNUAL REPORT
PIONEERING
TWO LARGE
OIL PLAYS
DeeThree Exploration Ltd. is drilling where others
wouldn’t, and succeeding where others didn’t.
We are the first to drill Alberta’s Upper Bakken siltstone,
and have been rewarded with a major pool discovery at
Ferguson – potentially the largest oil discovery in southern
Alberta in 10 years or more.
We are among the first to drill horizontal wells for Belly
River oil – and have an expanding multi-zone play at
Brazeau to show for it.
We are using today’s technologies for unlocking tight/
unconventional oil reservoirs: long-leg horizontal wells
completed with multi-stage fracturing using advanced
fluid systems.
CONTENTS
6
8
12
28
53
54
58
79
80
IBC
IBC
IBC
Highlights
Letter to Shareholders
Operations Review
Management’s Discussion and Analysis
Independent Auditors’ Report
Financial Statements
Notes to the Financial Statements
Corporate Governance
Committees of the Board
Corporate Information
Abbreviations
Conversion of Units
The Annual General Meeting of the shareholders of DeeThree Exploration Ltd.
will be held on Thursday, May 16, 2013 at 2:00 pm MDT in the Bow Glacier Room,
Third Floor, Centennial West Tower, 250-5th Street S.W., Calgary, Alberta.
WHAT HAS THIS
GIVEN US?
Two large, rapidly de-risking oil resource plays with internal
estimates of nearly one billion boe of original-oil-in-place.
Growing production of premium-priced oil. Increasing
cash flow. Accelerating momentum, with even broader
opportunities in 2013. And years of running room, with
hundreds of horizontal well locations.
BELIEVE IT
2012 Annual Report
1
2012: GROWTH
IN EVERY QUARTER
DeeThree delivered four consecutive quarters of growth in 2012: growth in
production of high-netback oil, growth in cash flow and growth in future
opportunity. Our operational tempo increased. In 2012, we spent a total of
$145 million, which included 30 gross wells overall, of which 25 were horizontal
drills in our key Alberta Bakken and Belly River oil plays. We also added
acreage and upsized oil batteries and other critical infrastructure. Key results:
59%
Average oil weighting was
59 percent in 2012.
$
Production reached year-end target of
6,000 boe per day, 75 percent oil and liquids.
32.66
20,188 mboe
Operating netback averaged
$32.66 per boe.
Successful drilling at Ferguson and Brazeau
delivered major reserve additions, with total
proved plus probable reserves of 20.2 million
boe at year-end 2012.
250%
Oil production grew by
250 percent year-over-year – from
only 1,000 bbls per day exiting
2011 to 3,500 bbls per day at
year-end 2012.
2
6,000 boe/d
DeeThree Exploration Ltd.
$
16.2 MM
Four quarters of production growth
drove sequential quarterly growth
in cash flow – from $5.7 million in
the first quarter to $16.2 million
in the fourth quarter.
6,000
PRODUCTION (BOE/D)
5,333
4,692
3,805
3,042
2,403
Q4
2011
Q1
Q2
Q3
Q4
EXIT
2012
IN SUMMARY:
WE DID WHAT WE SET OUT
TO DO. DEETHREE EXITED
2012 WITH MOMENTUM AND
IS DRIVING FORWARD IN 2013.
2012 Annual Report
3
BUILDING AN OIL GROWTH STORY
July 2012
Third-party resource evaluation estimates
222.1 million bbls of discovered oil initially in place
and 257.2 million bbls of undiscovered oil initially
in place resources at Ferguson.
2012
DeeThree drills a total of 25 gross horizontal
wells at Ferguson and Brazeau. Strong sequential
quarterly growth in production and cash flow.
December 2012
November 2008
January 2011
March 2013
DeeThree is founded. Freehold lands
acquired at Ferguson in southern Alberta
to pursue shallow gas opportunities.
DeeThree begins year with essentially
zero oil production and overall volumes of
only 500 boe per day.
Third-party evaluation estimates yearover-year reserves growth of 108 percent
to 20.2 million boe proved plus probable
at December 31, 2012.
At Ferguson, DeeThree drills the industry’s
first horizontal, multi-stage-fractured
well into the Upper Bakken siltstone,
confirming oil potential. Also at Ferguson,
DeeThree stratigraphic test discovers
major thickening in the Upper Bakken
siltstone. Triggers accelerated drilling.
March 2011
DeeThree uses cost-of-capital advantage
to raise equity, funding $125 million
acquisition which includes the Belly River
oil pool at Brazeau.
Summer 2011
At Brazeau, DeeThree drills its first
horizontal, multi-stage-fractured well.
Confirms development model for
Belly River tight sands.
December 2011
DeeThree exits 2011 with oil and liquids
production of 1,000 bbls per day.
4
2013
Production reaches year-end target of 6,000 boe
per day, 75 percent oil and liquids.
2011
2010
2008
Initial surge of Alberta Bakken oil
activity. Ferguson land position drives up
DeeThree’s market value.
2012
2010
DeeThree Exploration Ltd.
2013
$150 million capital program, funding a
planned 31 gross horizontal wells.
DEETHREE’S FUTURE: YEARS OF RUNNING ROOM,
ENORMOUS PRODUCTION AND RESERVES UPSIDE
DeeThree’s expanded 2013 capital program of $150 million includes 31 gross
horizontal wells. Year-end production is targeted at 8,500-9,000 boe per day, with
an even higher crude oil and liquids weighting of 81 percent. This year’s activities
will be largely funded by anticipated funds from operations of approximately
$100 million (based on benchmark oil pricing of US$95 per bbl WTI). Improving
infrastructure and pad drilling should further reduce operating costs. Innovative
marketing, including planned oil-by-rail exports, aims to maximize netbacks.
BUT IT’S ABOUT MORE THAN THIS YEAR’S PROGRAM.
CONSIDER DEETHREE’S LONG-TERM POSITIONING:
LARGE, HIGH-WORKING-INTEREST LAND BASE,
NOW AT 562 NET SECTIONS
+
INTERNAL ESTIMATES OF NEARLY ONE BILLION
BOE OF RESOURCE-IN-PLACE, ONLY 2 PERCENT
BOOKED AS RESERVES
+
+
=
RECENTLY ADDED FARM-IN LANDS
TWO EXTENSIVE AND STEADILY DE-RISKING PLAYS
MULTI-YEAR RUNNING ROOM – NOW AT 400 NET
HORIZONTAL LOCATIONS
+
UPSIDE IN PRODUCTION, RESERVES
AND CASH FLOW
2012 Annual Report
5
HIGHLIGHTS
Years Ended December 31,
(000s, except per share amounts)
Financial
Oil and natural gas revenues
Funds from operations (1)
Per share – basic
Per share – diluted
Cash flow from operating activities
Net income (loss)
Per share – basic
Per share – diluted
Capital expenditures (2)
Working capital deficit (3)
Shareholders’ equity
(000s)
Share Data
At period-end
Weighted average – basic
Weighted average – diluted
2012
2011
Change
($)
($)
(%)
85,112
46,088
0.69
0.68
62,292
7,181
0.11
0.11
144,753
77,586
212,090
32,747
11,833
0.21
0.21
7,100
(12,573)
(0.22)
(0.22)
187,557
16,901
167,568
160
289
229
224
777
157
150
150
(23)
(359)
27
(#)
(#)
(%)
71,080
66,902
68,130
63,152
56,407
56,407
13
19
21
(%)
Operating (4)
Production
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLs (bbls/d)
Total (boe/d)
Average wellhead prices
Natural gas ($/mcf)
Crude oil and NGLs ($/bbl)
Combined average ($/boe)
Netbacks
Operating netback ($/boe)
Funds flow netback ($/boe)
Reserves (December 31 evaluation)
Proved (mboe)
Proved plus probable (mboe)
Total net present value – proved plus probable
(10% discount, before taxes) ($000s)
Undeveloped land
Gross (acres)
Net (acres)
Gross (net) wells drilled
Natural gas (#)
Oil (#)
Standing (#)
Dry and abandoned (#)
Total (#)
Average working interest (%)
(1)
(2)
(3)
(4)
6
8,902
2,472
267
4,223
6,974
561
137
1,860
28
341
95
127
2.51
76.59
55.07
3.71
91.03
48.23
(32)
(16)
14
32.66
29.75
23.41
17.35
40
71
14,358
20,188
7,398
9,694
94
108
373,009
175,804
112
300,405
279,934
284,780
254,405
5
10
– (–)
28 (26.8)
2 (2.0)
– (–)
1 (1.0)
15 (13.0)
1 (0.4)
3 (3.0)
–
87 (106)
100 (400)
–
30 (28.8)
96
20 (17.4)
87
50 (66)
10
Funds from operations and funds from operations per share are not recognized measures under International Financial Reporting Standards (IFRS). Refer to
the commentary in the Management’s Discussion and Analysis under “Non-IFRS Measurements” for further discussion.
Total capital expenditures, including acquisitions and excluding non-cash transactions. Refer to commentary in the Management’s Discussion and Analysis
under “Capital Expenditures and Acquisitions” for further information.
Current assets less current liabilities, excluding current derivative financial instruments.
For a description of the boe conversion ratio, refer to the commentary in the Management’s Discussion and Analysis under “Other Measurements”.
DeeThree Exploration Ltd.
0.68
0.30
20,188
5,333
0.21
0.03
0.07
0.08
0.07
1,599
1,178
2,060
0.09
9,694
2,403
0.15
3,042
0.17
3,805
4,692
4,223
1,860
727
558
108
08 09 10 11 12
Q4 Q1 Q2 Q3 Q4
2012
11
12
08 09 10 11 12
08 09 10 11 12
08 09 10 11 12
AVG PRODUCTION
PRODUCTION
P+P RESERVES
P+P RESERVES
FUNDS FLOW
(BOE/D)
(BOE/D)
(MMBOE)
(BOE/SHARE)
($/SHARE)
CREATING SHAREHOLDER VALUE
In 2012 DeeThree delivered growth in all key financial
and operating metrics, not only in absolute terms – but
on a per-share basis. How? Our focus on oil delivered
high revenues per barrel produced. Growing efficiency
reduced operating costs per unit of production. High
per-barrel revenues plus efficient operations equal high
netbacks per barrel. That drives growth in cash flow.
Meanwhile, improving per-well results raised average
IP rates, delivering greater capital efficiencies and
increasing NPV per well.
2012 Annual Report
7
LETTER TO SHAREHOLDERS
The past year was once again busy and productive for DeeThree, with many successes. On the drilling
front, we were able to capitalize on two oil opportunities that will continue to drive the Company’s growth.
The year was highlighted by our Upper Bakken oil pool discovery at Ferguson in Southern Alberta
and by the Belly River multi-zone enhancement project in the Brazeau area – both of which triggered
multi-horizontal well delineation programs that will provide for future growth and expansion. On the
operational front, we grew oil production, increased netbacks, reduced operating and G&A costs and
met our year-end production target. This allowed us to enter 2013 with momentum, strategically adding
acreage and raising equity early in the year.
Operations DeeThree’s Upper Bakken pool discovery at Ferguson in January 2012 was followed up with
16 additional 100 percent DeeThree horizontal wells. All 17 wells were successful and we now estimate
the pool’s area at approximately 40 square miles, with much of the boundary yet to be reached. DeeThree
entered 2012 with area production of only 750 boe per day from this area, of which 40 percent was crude
oil and liquids. As of March 2013 Ferguson is generating over 3,000 boe per day, 87 percent crude oil
and liquids.
To substantiate the discovery’s impact, we hired a third party to conduct a
Our Upper Bakken pool
discovery was followed
by 16 horizontal wells.
resource study in the summer of 2012. It allocated discovered oil initially in
place of 222.1 million barrels with a best estimate of recoverable resource of
21.8 million bbls in addition to the reserves produced and booked to date and
undiscovered oil initially in place resources of 257.2 million bbls with a best
estimate of recoverable resources of 30.9 million barrels. To put this figure
into perspective, the Company exited 2011 with proved plus probable reserves of only 2.3 million boe
attributed to Ferguson. We believe that this could be the biggest oil discovery in southern Alberta in the
last 10 years. It is something our geological and geophysical team is justly very proud of. At year-end
2012, reserves assigned to Ferguson had grown to 10.7 million boe proved plus probable. DeeThree also
owns and operates all area infrastructure. In 2012 we expanded our oil battery’s capacity to 6,000 bbls
per day and before year-end began procurement of equipment for a second battery of equal size, which
should become operational in the second half of 2013.
8
DeeThree Exploration Ltd.
Our goal in 2012 for our Brazeau property was to systematically prove up the six untapped horizons in
the Belly River Formation through horizontal drilling. Years of previous vertical drilling had focused on the
Basal zone which is the deepest-lying. This provides extensive well control to choose horizontal locations
in multiple overlying zones. Our drilling program in 2011 had established the Basal zone as amenable to
horizontal development. In our eight-well 2012 program we drilled a further six gross (5.7 net) wells into new
intervals. All were successful and we exited the year with four separate Belly River zones producing from
horizontal, multi-stage-fractured wells.
The results at Brazeau not only contributed 2.3 million boe of new proved plus probable reserves as of yearend 2012 but also provides for years of future horizontal drilling. When we purchased the area in spring 2011,
we believed there was enormous potential and untapped value which others had missed.
On the acquisition front, the Company worked to consolidate its working
interests, particularly at Brazeau, increasing its average interest in the area from
89 percent to 97 percent. We also participated in multiple Crown land sales
in the Ferguson area, strategically accumulating most of the available Crown
land around our property. Capital expenditures for 2012 on drilling, land and
2012 was a
demonstration of
operational excellence
and growth on all fronts.
infrastructure totalled $145 million.
2012 Results We demonstrated operational excellence and generated significant growth on all fronts
in 2012: production, cash flow, reserves, drilling inventory and net asset value, to name a few.
Highlights include:
s
Achieved 100 percent success on 30 gross (29 net) wells;
s )NCREASEDPRODUCTIONFROMANANNUALAVERAGEOFBOEPERDAYINTOANANNUALAVERAGEOF
4,223 boe per day in 2012;
s &URTHERINCREASEDOUROILWEIGHTINGFROMPERCENTENTERINGTOPERCENTATYEAREND
s )N/CTOBERINCREASEDOURCREDITFACILITYFROMMILLIONTOMILLIONWITHASYNDICATEOFTWOBANKS
and exited the year with net debt of $78 million;
2012 Annual Report
9
s 2EDUCEDYEAROVERYEARNET'!COSTSPERUNITOFPRODUCTIONBYPERCENTFROMPERBOEIN
2011 to $2.78 per boe in 2012;
s 2EDUCEDOPERATINGCOSTSYEAROVERYEARSHOWINGPARTICULARIMPROVEMENTINTHEFOURTHQUARTERWITH
operating costs declining by 55 percent from $17.87 per boe in the fourth quarter of 2011 to $8.05
per boe in the fourth quarter of 2012;
s )NCREASEDOURAVERAGENETBACKFROMPERBOEINTOPERBOEIN
s 'REWFUNDSFROMOPERATIONSFROMMILLIONPERSHAREINTOMILLIONPER
share) in 2012, achieving growth in each quarter;
s )NCREASEDRESERVESBYPERCENTYEAROVERYEARTOMILLIONBOEPROVEDPLUSPROBABLEAT
December 31, 2012, according to our most recent third-party evaluation by Sproule Associates
Limited;
s 2EPLACEDPRODUCTIONBYTIMESTHROUGHPROVEDPLUSPROBABLERESERVEADDITIONSANDEXITED
2012 with a reserve-life-index, based on the 2012 fourth quarter average production, of 10.4 years;
s !DDEDNEWRESERVESATANAVERAGElNDINGANDDEVELOPMENTCOSTOFPERPROVEDPLUS
probable boe; and
s 'REWTHENETPRESENTVALUEPERCENTDISCOUNTBEFORETAXOF$EE4HREESASSETBASEBY
percent year-over-year, to an estimated $373.0 million at December 31, 2012.
Outlook DeeThree entered 2013 well-positioned as a focused oil producer with high working interests in
two large, game-changing oil plays. The Company controls and operates both plays, so is able to change
the pace of drilling and allocate capital to align with cash flow and commodity price volatility.
We were pleased at the capital markets’ positive reaction to our equity issuance earlier in the first quarter.
It raised gross proceeds of $34.5 million and supports the Company’s planned 2013 capital program of
approximately $150 million. This budget provides for the drilling of 31 net horizontal wells, including 20 net
Upper Bakken wells and 11 gross (10.7 net) Belly River wells. Five of the year’s wells will be exploratory.
At Ferguson, we are continuing to delineate and extend the Upper Bakken pool while drilling two
prospects identified on recently acquired Crown lands. A recent delineation well included a lateral leg
over two miles in length and achieved an IP30 of 448 boe per day. The longer lateral legs aim to delineate
as much resource as possible and/or extend pool boundaries, while lowering capital costs per unit of
production and reserves added. Recent land acquisitions bring the Ferguson play to a total of 75 net
sections, giving us more running room than we had one year earlier, even as we de-risk the play.
10
DeeThree Exploration Ltd.
Drilling results to date in 2013 continue to be strong. At Brazeau we proved up the D zone of the Belly
River formation with a well that tested at 1,190 boe per day, as announced in late February. We have
also started to drill the first two commitment wells on our recent 34-section farm-in that has the potential
to double the size of our Brazeau property. Eventually we aim to initiate a multi-well pad drilling model at
Brazeau that will enable each pad to develop 160 acres in four zones. Pad drilling will increase per-well
capital efficiencies and reduce spud-to-on-stream times.
For 2013 we are forecasting year-over-year production growth of approximately 67 percent, to an average
rate of 6,800-7,000 boe per day, and an exit rate of 8,500-9,000 boe per day. The production weighting
at year-end is expected to be approximately 81 percent crude oil and liquids and 19 percent natural gas.
Based on anticipated average production and projected prices of US$95.00 per barrel WTI, Cdn$3.20
per mcf natural gas and an exchange rate of US$1.00/Cdn$0.99, DeeThree is forecasting 2013 funds
from operations of $100 million. The corporate oil price differential is forecast at 20 percent of WTI, which
reflects the current market environment. Our balance sheet is forecast to remain strong, with projected
year-end net debt to fourth quarter annualized funds from operations of approximately 0.8:1.0.
DeeThree’s strong success is a direct result of the commitment, focus and dedication of our valued
employees, consultants and Board of Directors. After delivering year-over-year growth in all critical aspects
of the business in 2012, we believe we can continue this momentum throughout 2013 and beyond.
On behalf of the Board of Directors,
Martin Cheyne
President, Chief Executive Officer and Director
March 26, 2013
2012 Annual Report
11
OPERATIONS REVIEW
SEEING NEW OPPORTUNITIES
EXPLORING UNDRILLED LANDS
DeeThree is delivering oil production growth through the drill bit. The Company uses a mix of grassroots
exploration in undrilled areas and applying new technologies to increase recoveries in known oil pools. At
Ferguson, DeeThree confirmed commerciality of the Upper Bakken siltstone – and made potentially the
largest oil pool discovery in southern Alberta in 10 years or more. At Brazeau, DeeThree is an industry
pioneer in revitalizing the Belly River tight sands through horizontal drilling and multi-stage fracturing.
At each of Ferguson and Brazeau, DeeThree holds a large, high-working-interest land base, controls critical
infrastructure and has a multi-year inventory of drilling locations. Both plays generate long-life production,
large reserves per well and high netbacks. At Ferguson, for 2013, DeeThree is focusing on pool delineation
and de-risking of the Upper Bakken siltstone, further pool extension and testing of recently identified new oil
prospects. At Brazeau, with recent drilling having proved the fifth Belly River zone, DeeThree is testing the
sixth zone while pursuing low-risk multi-zone development plus delineation of recently added farm-in lands.
Both plays offer years of running room, with average spacing to date of significantly less than one horizontal
well per section of land.
OIL: THE PREMIUM HYDROCARBON
Oil production is measured in terms of API gravity. Light crude has an API gravity higher than 31.1°,
medium crude has an API gravity between 22.3° and 31.1°, and heavy crude has an API gravity below
22.3°. West Texas Intermediate (WTI) is the benchmark crude oil used by the United States to set prices
and compare to other crude oils. WTI oil has an API gravity of 38°-40°. In Alberta, most oil production is
heavy crude, which is worth less because it requires more processing. As a result, lighter oil is a much
sought-after commodity.
DeeThree’s Belly River production at Brazeau averages 42° API and sells at a premium to the Alberta Par
benchmark, generating netbacks of over $60 per bbl. Upper Bakken siltstone production at Ferguson
averages 31° API and is a unique oil, being high in aromatics.
At Ferguson, Deethree is working to capture higher product pricing by incorporating oil-by-rail marketing,
possibly through the construction of a rail-loading terminal. Reductions in overall operating costs, from
$12-$15 per boe in early 2012 to below $10 per boe in early 2013, are also helping to lift netbacks.
DeeThree continues to make smart investments in infrastructure in both of our key areas, leading to
operating efficiencies now and for the future.
12
DeeThree Exploration Ltd.
BRAZ
EAU
FERG
Total lands at year-end 2012:
359,768 net acres at 86.8 percent average WI
Ferguson: 267,697 net acres at 99 percent average WI
Brazeau: 29,964 net acres at 83 percent average WI
Early 2013 farm-in will add up to
21,187 net acres
2012 gross wells drilled:
17 hz Alberta Bakken at Ferguson
8 hz Belly River at Brazeau
4 Sunburst at Ferguson
1 non-operated in Peace River Arch
USON
2013 planned drilling:
20 gross hz Alberta Bakken at Ferguson
11 gross hz Belly River at Brazeau
Future horizontal well locations:
200 at Ferguson
200 at Brazeau
Reserves at Dec. 31, 2012 (proved plus probable):
Ferguson: 10.7 mmboe, 85 percent oil
Brazeau: 7.6 mmboe, 70 percent oil and liquids
*Does not include lands added Crown sales at Ferguson or farm-in at Brazeau in late 2012.
2012 Annual Report
13
FIRST IN ALBERTA’S UPPER BAKKEN SILTSTONE
THE GEOLOGY OF THE UPPER BAKKEN SILTSTONE
DeeThree has created an in-house geological model of the Upper Bakken siltstone at Ferguson. Although this
Mississippian-age rock appears unpromising on well logs, coring of widely separated wells at Ferguson suggests a
continuous ribbon of siltstone, rich in conodont fossils, likely deposited as an offshore bar. The siltstone lies at an average
depth of 1,500 metres and has a thickness of 2-14 metres. The Upper Bakken overlies both of the Alberta Bakken’s shale
intervals, the play’s source rock, and differs from the Middle Bakken siltstone targeted by most other area operators. The
Middle Bakken is much higher in clay and silt, making it much more difficult to stimulate through hydraulic fracturing.
The Upper Bakken siltstone has average porosity of 9 percent and average permeability of approximately 5 millidarcies,
less “tight” than many unconventional reservoirs. It is virtually free of clay. DeeThree has mapped the pool over an area of
approximately 75 sections (of which 40 have been tested), but its western and eastern edges remain undefined, and two
further undrilled prospects have been identified outside of this area. Delineation and testing are key objectives for 2013.
EXPLORING THE UPPER BAKKEN SILTSTONE
August 2011
Third horizontal well duplicates
positive results of first well.
October 2008
279 net sections of freehold land
acquired at Ferguson for $19 million,
with the goal of developing Bow Island
shallow gas.
2010
Horizontal drilling across the broad
Alberta Bakken fairway gathers
momentum.
January 2012
2013
3,600
February 2012
201
2
1,900
January 2011
DeeThree drills exploration well at
Ferguson, an undeveloped area with no
previous oil production. Coring reveals
36 metres of oil column and best
drilling opportunity in Upper Bakken.
DeeThree drills horizontal leg. Well
achieves 30-day IP of 180 bbls per
day, with no water and little natural
gas. These are the first oil barrels ever
taken out of the Upper Bakken.
March 2011
DeeThree’s second horizontal well at
Ferguson drilled on seismic along fault.
Well contains water.
14
DeeThree Exploration Ltd.
Vertical stratigraphic test well drilled on
the eastern land base discovers major
thickening in the Upper Bakken siltstone.
201
1
20
10
570
675
Fifth horizontal well at Ferguson, over
20 miles from original well, comes
on-stream at 700 bbls per day.
Wireline logs suggest a large,
newly discovered pool.
May 2012
A further 35 sections of Crown lands
acquired at 100 percent WI, subject
to 5 percent royalty on new horizontal
production.
August 2012
20
09
500
Total Average Production in boe/d
Third-party resource estimate suggests
Upper Bakken at Ferguson contains
contingent and prospective oil resources
of 222.1 mbbls of discovered oil
initially in place and 257.2 mbbls of
undiscovered oil initially in place.
Bakken/Exshaw
Petroleum System
Exshaw
Calgary
Saskatoon
Swift Current
Alberta Basin
Exshaw Channels
Williston Basin
Nesson
Anticline
R22
T10
R21
R20
R19
R18
R17
R16
R15W4
T9
2012
DeeThree drills a total of 17 horizontal
wells at Ferguson, all successful and
on-production by early 2013. Ferguson
production grows to 3,000 bbls per day
exiting 2012.
T8
T7
T6
Dec. 2012 - Jan. 2013
DeeThree acquires an additional 20
net sections of land, increasing the
Ferguson play to 75 net sections at
an average 100% percent WI, the
industry’s second largest land base in
the Alberta Bakken.
2013
20 net horizontal wells are planned
for the year, including delineation
and exploration wells to the east,
west and north of the core pool, and
extended-reach laterals with up to
40 fracturing stages.
T5
T4
T3
T2
T1
Ferguson Land & Infrastructure
DeeThree land
Freehold land
Pipelines
Roads
2012 Annual Report
15
2013 PLANS
DeeThree’s objectives in the Alberta Bakken in 2012 were to confirm the play’s overall viability, to de-risk the technical
unknowns, to begin generating production growth and to add further lands. Results exceeded expectations. The year’s first
horizontal Bakken well came on-stream in February at 700 bbls per day. Even more significant, it strengthened the evidence
for a large, continuous pool, suggested by well logs and seismic data, with an approximate size of 10x4 miles – potentially
the largest oil discovery in southern Alberta in 10 years or more. An even larger prospective area stretches more than 25
miles to DeeThree’s original Bakken horizontal well to the west.
The discovery triggered an accelerated Upper Bakken siltstone drilling program in 2012 of 17 net horizontal wells. All were
successful and, as the year progressed, average per-well costs declined while initial productivity increased. Entering 2013,
production at Ferguson had grown to 3,000 bbls per day. After initially installing single-well batteries, DeeThree laid pipelines
and tied the wells into an oil battery that in late 2012 was expanded to capacity of 6,000 bbls per day, with an additional
6,000 bbls per day battery planned to be on-stream by the second half of 2013. The battery lies close to a railway to the
United States and DeeThree is considering construction of a rail-loading terminal, enabling direct export to seek Brent crude
price exposure in U.S. markets.
R19
R18
R17
R16
T4
T3
Type Curve
T2
Ferguson Drilling Program
DeeThree land
Freehold land
16
DeeThree Exploration Ltd.
Pipeline
Horizontal well
Planned Horizontal well
R15W4
DeeThree has a 20-horizontal-well program underway at the year-round access Ferguson play for 2013.
Key objectives are to delineate the current pool’s eastern boundary, to extend its undefined western
boundary as far as possible, and to test two recently identified prospects to the north. The Company
added Crown lands in all three directions in 2012 and early 2013. The final well of 2012 extended the
eastern boundary and in early 2013 had an IP30 of 448 bbls per day, plus natural gas.
Further refinements to drilling and completions techniques are also important objectives. Horizontal legs
are being extended. A recent eastern well was pushed beyond 5,000 metres total measured depth,
including a horizontal leg of approximately 3,500 metres, without reaching the boundary of the reservoir.
Spacing of fracturing stages is being tightened and wells could receive as many as 40 fracture stages
each. Fracturing fluid is typically nitrified gelled water. Pumping rates and proppant amounts have been
optimized to prevent fracture propagation outside the reservoir. Longer horizontal legs will increase perwell costs but are aimed at reducing costs per unit of production and reserves added. The Company will
also initiate reinjection of produced natural gas for reservoir pressure maintenance.
DeeThree is targeting production growth to 5,300 boe per day at Ferguson by year-end 2013. Over time,
DeeThree foresees developing the Upper Bakken pool at Ferguson with spacing of approximately four
wells per section.
2012 Annual Report
17
UNLOCKING BRAZEAU BELLY RIVER OIL
SEEING VALUE WHERE OTHERS DON’T
The Belly River Formation is a sinuous, channelized, Upper Cretaceous sandstone common in Alberta, primarily as a
natural gas reservoir. At Brazeau it lies at approximately 1,800 metres’ depth and is light-oil-bearing, with 20-25 percent
solution gas containing approximately 65 bbls of liquids per mmcf of raw gas. The reservoir is highly variable, with
porosity of 3-18 percent and permeability of 0.1-100 millidarcies. It has Deep Basin characteristics, including very low
water content. The reservoir is highly amenable to horizontal drilling and multi-stage fracturing, enabling intersection of
high-quality reservoir pockets often missed by vertical wells.
DeeThree’s broad goal at Brazeau is to expand the play by establishing commerciality in multiple Belly River intervals.
Historically, producers focused on the large Basal section, which is easiest to find with vertical wells. Using logs from
the historical producing base of 60 vertical wells, DeeThree has mapped six prospective Belly River zones at Brazeau.
By February 2013, DeeThree had established five of these as amenable to horizontal development: the Basal Marine,
Basal Fluvial and Upper G, D and C.
REVITALIZING THE BELLY RIVER THROUGH
HORIZONTAL DEVELOPMENT
March 2011
December 2011
DeeThree acquires a total of 35
sections of land, strategic facilities and
980 boe per day of low-decline, oil
and liquids-rich gas production from
60 vertical wellbores at Brazeau,
as part of a larger $125 million
acquisition.
Two further horizontal wells are drilled
and completed before year-end. The
most significant is completed with
a 16-stage hydraulic fracture and
produces at a stabilized rate after five
days of 600 bbls per day of 44° API
oil and 250 mcf per day of liquids-rich
gas. DeeThree exits the year at 1,117
boe per day, not including initial
flow-backs on the year’s final wells.
July 2011
DeeThree drills its first Companyidentified horizontal well into the
Basal Belly River, with a total
measured depth of 3,054 metres,
completed with 13 fracturing stages
using an advanced foam-based fluid
system. Well comes on-stream at 250
boe per day, confirming horizontal
revitalization concept.
January 2012
2013
201
2
DeeThree drills its first well into the
Belly River Marine sand, substantiating
the potential beyond the Basal. The
next Brazeau well comes on at 230 boe
per day.
20
11
2,700
1,500
1,000
Total Average Production in boe/d
18
DeeThree Exploration Ltd.
Surface
Belly River
Base
Bearpaw Formation
1,550 m
Belly River
Fluvial/
Anamastomosed
System
‘Marine’
Belly River
1,900 m
Lea Park/Milk River
Formation
March 2012
First horizontal well into the Upper C
zone pool is drilled – and becomes the
Company’s best at Brazeau to date. It
comes on-stream at 485 boe per day
and in its first six months on-production
produces a cumulative 30,480 bbls
of oil.
Year-End 2012
DeeThree exits 2012 with production
at Brazeau of 1,800 boe per day, not
including test volumes from the year’s
final wells. Horizontal drilling activity
from the initial acquisition to year-end
2012 totals 12.1 net wells.
October 2012
Acquisition for $7 million in cash
consolidates working interest in
DeeThree’s Brazeau infrastructure.
Remainder of 2012
December 2012
New farm-in agreement allows
DeeThree a rolling option to drill Belly
River oil wells to earn 100 percent
working interest over 34 net sections.
February 2013
First well into the D zone tests at
1,190 boe per day, 45 percent crude
oil and liquids, DeeThree’s fifth Belly
River zone substantiating through
horizontal drilling.
DeeThree continues to prove the Upper
Belly River sands with three further
successful wells and continues to
delineate the Basal and Marine sands.
2012 Annual Report
19
BRAZEAU BELLY RIVER
With extensive vertical well control in a known pool, DeeThree’s primary task at Brazeau was to de-risk its horizontal
development model while testing up to six prospective intervals within the Belly River. The large resource base – Brazeau is one
of western Canada’s three largest Belly River pools – with a low recovery factor of 2.5 percent under vertical development
provides the broad opportunity.
DeeThree’s well completions approach of 12-15 fracturing stages per horizontal well, using foam-based fracturing fluid to place
30 tonnes of proppant per stage, achieved immediate success in the initial Basal target zone. That enabled rapid progression
into testing undeveloped intervals, plus drilling across the play to locate the best reservoir areas. The upper zones
outperformed expectations, and significant reserve additions were recorded for 2012.
DeeThree had budgeted a 30-day IP of approximately 150 boe per day, with a 70 percent first-year production decline. But
recent wells have delivered 280-400 boe per day and had production exceeding 200 boe per day up to five months after
coming on-production. The first well drilled into the D zone tested in early 2013 at 1,190 boe per day, 45 percent crude oil and
liquids, and the sixth zone was tested by the end of the first quarter. Ample available infrastructure has enabled horizontal wells
to be drilled on existing vertical well-sites, then tied-in, brought on-stream and earning revenue within days of completion.
R16
R15
T49
T48
T47
T46
Brazeau Land & Drilling Program
DeeThree land
Freehold land
20
DeeThree Exploration Ltd.
Unitizied lands
Horizontal well
Planned horizontal well
R14
R13W5
By early 2013 the Belly River had been substantially de-risked on the initial, 36-section block. With a
total of 11 gross horizontal wells planned for 2013, out of a current inventory of up to 200 locations,
development on the original play will shift into an infill mode using multi-well drilling pads, with each well
capable of producing from up to four zones over a planned 160 areas. This approach is expected to
reduce average per-well costs to approximately $3.5 million. Meanwhile, DeeThree quickly began to drill
the less developed farm-in area, obtained in December 2012, which could double the Brazeau play’s
horizontal inventory. DeeThree is targeting production growth to approximately 3,300 boe per day at
Brazeau by year-end.
2012 Annual Report
21
Sales Summary
Three Months Ended December 31,
Years Ended December 31,
2012
2011
2012
2011
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLs (bbls/d)
9,377
3,511
259
7,714
957
161
8,902
2,472
267
6,974
561
137
Total (boe/d)
5,333
2,403
4,223
1,860
Land Summary
Undeveloped
Developed
Total
Gross
Net
Gross
Net
Gross
Net
(acres)
(acres)
(acres)
(acres)
(acres)
(acres)
2012
Lethbridge
Brazeau
Peace River Arch
Other
230,878
18,880
42,800
7,847
229,689
16,104
28,232
5,909
40,125
17,120
49,692
7,040
38,008
13,860
23,492
4,474
271,003
36,000
92,492
14,887
267,697
29,964
51,724
10,383
Total
300,405
279,934
113,977
79,834
414,382
359,768
Lethbridge
Brazeau
Peace River Arch
Other
202,300
19,200
56,720
6,560
199,852
15,761
33,848
4,944
62,348
15,360
49,202
8,970
61,201
11,097
22,440
5,406
264,648
34,560
105,922
15,530
261,053
26,858
56,288
10,350
Total
284,780
254,405
135,880
100,144
420,660
354,549
2011
As at December 31, 2012, DeeThree controlled petroleum and natural gas leases covering 279,934 net acres of undeveloped
land, a 10 percent increase from the 254,405 net acres held at the end of 2011.
During 2012, DeeThree invested $619,000 for the acquisition of 1,900 net acres of petroleum and natural gas rights in the Peace
River Arch and Brazeau areas at an average cost of $326 per acre and $10,623,000 for the acquisition of 40,000 net acres of
petroleum and natural gas rights in the Lethbridge area at an average cost of $266 per acre.
22
DeeThree Exploration Ltd.
Reserves
Sproule Associates Limited (“Sproule”), an independent petroleum engineering firm, evaluated the natural gas, crude oil and NGLs
reserves of the Company as at December 31, 2012 and 2011. Sproule based their evaluation on land data, well and geological
information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating
cost data, capital budget forecasts and future operating plans provided by DeeThree, and prepared their report in accordance with
the Canadian Securities Administrators National Instrument NI 51-101 – Standards of Disclosure for Oil and Gas Activities. The
required disclosure of the reserves estimates and future net revenue of the Company as at December 31, 2012, based on forecast
prices and costs, are outlined below along with the economic assumptions used in preparing those estimates. For purposes of
computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet of
gas to one barrel of oil. This conversion ratio of 6:1 is based on an energy equivalent conversion for the individual products at the
burner tip and does not represent a value equivalency at the wellhead. Such disclosures of boes may be misleading, particularly if
used in isolation. Also refer to the disclosure under “Statement of Reserves Data and Other Oil and Gas Information ” included in
the Company’s Annual Information Form for the year ended December 31, 2012.
Summary of Oil and Gas Reserves
The following table outlines the oil and gas reserves of the Company by product type on a gross (before royalties) and net (after
royalties) basis:
Crude Oil
Natural Gas
NGLs
Total
Gross
Net
Gross
Net
Gross
Net
Gross
Net
(mbbls)
(mbbls)
(mmcf)
(mmcf)
(mbbls)
(mbbls)
(mboe)
(mboe)
Proved
Developed producing
Developed non-producing
Undeveloped
4,309
141
6,020
3,410
97
4,494
12,610
1,185
5,490
11,244
945
4,866
415
4
255
283
2
188
6,825
342
7,190
5,566
257
5,492
Total proved
Developed producing
Developed non-producing
Undeveloped
10,470
1,634
49
2,611
8,000
1,233
33
1,830
19,285
5,480
372
1,926
17,056
4,840
300
1,689
674
158
6
76
472
103
4
50
14,358
2,705
117
3,008
11,315
2,143
87
2,161
4,294
3,096
7,777
6,829
240
157
5,830
4,391
14,764
11,096
27,062
23,885
913
630
20,188
15,706
Probable
Total proved plus probable
Note: Table may not be additive due to rounding.
Net Present Values of Future Net Revenue
The net present values of future net revenue of the Company’s reserves at various discount rates on a before tax basis are outlined
below.
Before Income Taxes Discounted At
0%
5%
10%
15%
20%
($)
($)
($)
($)
($)
Proved
Developed producing
Developed non-producing
Undeveloped
233,331
7,567
175,150
191,474
6,043
127,448
163,837
4,984
94,144
144,349
4,216
69,823
129,889
3,637
51,407
Total proved
Probable
416,048
235,031
324,964
153,001
262,965
110,044
218,387
84,745
184,933
68,441
Total proved plus probable
651,079
477,965
373,009
303,132
253,375
(000s)
Note: Table may not be additive due to rounding.
2012 Annual Report
23
Reconciliation of Company Interest Reserves by Principal Product
The reconciliation of the Company’s gross proved, probable and proved plus probable reserves for December 31, 2012 is
as follows:
Crude Oil
January 1, 2012
Extensions
Infill
Discoveries
Techincal revisions
Economic factors
Production
December 31, 2012
Natural Gas
Proved
Probable
Proved
Plus
Probable
Proved
Probable
Proved
Plus
Probable
(mbbls)
(mbbls)
(mbbls)
(mmcf)
(mmcf)
(mmcf)
3,521
1,955
6,068
240
(415)
6
(905)
1,088
766
2,419
(40)
58
2
–
4,609
2,721
8,487
200
(357)
8
(905)
20,153
729
4,004
150
(1,735)
(757)
(3,258)
6,447
326
1,675
(102)
(496)
(74)
–
26,600
1,055
5,679
48
(2,231)
(831)
(3,258)
10,470
4,294
14,764
19,285
7,777
27,062
NGLs
Total
Proved
Probable
Proved
Plus
Probable
Proved
Probable
Proved
Plus
Probable
(mbbls)
(mbbls)
(mbbls)
(mboe)
(mboe)
(mboe)
January 1, 2012
Extensions
Infill
Discoveries
Techincal revisions
Economic factors
Production
518
8
177
2
72
(5)
(98)
133
3
83
(1)
24
(2)
–
651
10
260
1
96
(7)
(98)
7,397
2,084
6,912
267
(632)
(126)
(1,545)
2,296
823
2,782
(58)
(0)
(13)
–
9,694
2,908
9,694
209
(633)
(138)
(1,545)
December 31, 2012
674
240
913
14,358
5,830
20,188
Note: Table may not be additive due to rounding.
Note: Gross reserves mean the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests.
24
DeeThree Exploration Ltd.
Total Future Net Revenue
The following table provides a breakdown of the various components of total future net revenue on an undiscounted basis for
proved and proved plus probable reserves:
Development
Costs
Well
Abandonment
Costs
Future Net
Revenue
Before
Income
Taxes
Revenue
Royalties
Operating
Costs
($)
($)
($)
($)
($)
($)
196,065
198,002
122,293
96,239
74,612
59,351
48,404
40,033
33,333
28,524
24,531
21,262
52,545
55,657
35,164
27,852
18,097
11,983
8,111
5,727
4,193
3,230
2,550
2,070
23,718
24,800
19,181
16,566
14,974
13,697
12,691
11,592
10,564
10,076
9,565
9,060
150,346
1,443
–
–
–
–
–
–
–
–
–
–
132
88
230
45
52
164
118
311
138
136
120
233
(30,675)
116,014
67,717
51,776
41,491
33,507
27,484
22,403
18,438
15,083
12,296
9,900
98,300
8,801
54,854
4,027
30,614
1,040,949
235,980
231,338
151,789
5,794
416,048
Proved plus probable
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
216,069
234,807
155,891
128,721
103,615
85,273
71,849
61,660
53,139
46,214
40,726
36,252
57,899
68,861
49,000
42,281
30,085
21,962
16,590
12,628
9,569
7,495
6,026
4,978
25,479
27,911
22,249
19,373
17,567
16,155
15,157
14,318
13,412
12,465
11,814
11,234
157,349
1,598
–
–
–
–
–
–
–
–
–
–
–
90
247
46
96
93
108
77
213
239
125
231
(24,658]
136,348
84,395
67,020
55,867
47,064
39,994
34,637
29,945
26,017
22,761
19,809
Remainder
287,947
32,278
138,748
–
5,039
111,880
1,522,163
359,652
345,882
158,947
6,604
651,079
(000s)
Proved
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Remainder
Total proved
Total proved
plus probable
Note: Table may not be additive due to rounding.
2012 Annual Report
25
Summary of Pricing and Inflation Rate Assumptions
The economic parameters, as determined by Sproule, assumed in preparing the forecast prices and costs reserves report are
outlined below.
Price Forecast – Effective December 31, 2012
Year
Historical
2008
2009
2010
2011
2012
Forecast
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
Remainder
Currency
Exchange
Rate
WTI
Cushing
Oklahoma
Edmonton
Light
Par
Henry
Hub
Louisiana
Alberta
AECO-C
Spot
(US$/CDN$)
(US$/bbl)
(CDN$/bbl)
(US$/mmbtu)
(CDN$/GJ)
0.943
0.880
0.971
1.012
1.001
99.59
61.63
79.43
95.00
94.19
102.85
66.20
77.80
95.16
86.53
9.04
4.01
4.39
4.04
2.79
8.15
4.19
4.16
3.72
2.43
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
89.63
89.93
88.29
95.52
96.96
98.41
99.89
101.38
102.91
104.45
84.55
89.84
88.21
95.43
96.87
98.32
99.79
101.29
102.81
104.35
3.65
4.06
4.24
5.04
5.66
5.74
5.83
5.91
6.00
6.09
3.31
3.72
3.91
4.70
5.32
5.40
5.49
5.58
5.67
5.76
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
Reserve Life Index
The reserve-life-index of DeeThree has been calculated using 2013 estimated gross production volumes and gross proved and
proved plus probable reserves using forecast prices and costs, all of which were taken from the December 31, 2012 Sproule
reserves report. The reserve-life-index of the Company as at December 31, 2012, on a boe basis, was 5.1 years for total proved
reserves and 6.5 years for total proved plus probable reserves.
Proved
26
Proved
Plus
Probable
Proved
Expected
2013
Production
Proved
Plus
Probable
Expected
2013
Production
Proved
Proved
Plus
Probable
(years)
(years)
Natural gas (mmcf)
Crude oil and NGLs (mbbls)
19,285
11,143
27,062
15,677
2,993
2,338
3,125
2,600
6.4
4.5
8.7
5.7
Total (mboe)
14,358
20,188
2,837
3,120
5.1
6.5
DeeThree Exploration Ltd.
Finding and Development Costs and Recycle Ratio
The recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the
efficiency of capital investment, which is accomplished by comparing the operating netback per boe to that year’s reserves’ finding
and development (“F&D”) cost per boe. For the year ended December 31, 2012, DeeThree’s recycle ratio was 1.1 times on a
proved basis and 1.5 times on a proved plus probable basis, while the Company achieved an average F&D cost of $30.21/boe on
a proved basis and $21.51/boe on a proved plus probable basis.
The table below provides detailed calculations relating to F&D costs and recycle ratios for the Company’s proved and proved plus
probable reserves for the years ended December 31, 2012 and 2011.
Years Ended December 31,
2012
2011
144,753
112,151
256,904
188,941
39,028
227,969
Reserves additions (mboe)
8,505
6,750
F&D costs, excluding future development costs ($/boe)
F&D costs, including future development costs ($/boe)
Operating netback ($/boe)
17.02
30.21
32.66
27.99
33.77
23.41
1.1
0.7
144,753
114,200
258,953
188,941
44,137
233,077
12,039
8,774
12.02
21.51
32.66
21.53
26.56
23.41
1.5
0.9
Proved Reserves
Capital expenditures ($000s)
Change in future capital ($000s)
Total capital costs ($000s)
Recycle ratio
Proved Plus Probable Reserves
Capital expenditures ($000s)
Change in future capital ($000s)
Total capital costs ($000s)
Reserves additions (mboe)
F&D costs, excluding future development costs ($/boe)
F&D costs, including future development costs ($/boe)
Operating netback ($/boe)
Recycle ratio
(1)
(2)
For a description of the boe conversion ratio, refer to the commentary at the beginning of the Management’s Discussion and Analysis.
The aggregate of the exploration and development costs incurred in 2012 and the change during the year in estimated future development costs may not reflect
total F&D costs related to reserves additions for the year.
Net Asset Value
Years Ended December 31,
2012
2011
($)
($)
Present value of petroleum and natural gas reserves (1)
Net undeveloped land (2)
Working capital deficit
Proceeds from stock options (3)
373,009
62,483
(77,586)
18,193
175,804
51,846
(16,901)
1,596
Net asset value
376,099
212,345
76,779,805
4.90
64,029,591
3.32
(000s, except per share amounts)
Diluted shares outstanding (4)
Net asset value per share
(1)
(2)
(3)
(4)
Total proved plus probable, discounted at 10%, before tax per the Sproule December 31 reserves evaluations.
Based on a third party evaluation as at December 31, 2012 and 2011.
Calculated proceeds from in-the-money options using a 2012 year-end closing common share price of $6.51 per share (2011 – $2.05 per share).
Calculated as basic shares outstanding at December 31 plus in-the-money options.
2012 Annual Report
27
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management’s Discussion and Analysis (MD&A) of the financial condition and results of operations for DeeThree
Exploration Ltd. (“DeeThree” or the “Company”) is dated March 26, 2013 and should be read in conjunction with the Company’s
audited financial statements and related notes for the years ended December 31, 2012 and 2011. The financial statements
were prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting
Standards Board (IASB).
Additional information regarding the Company and factors that could affect its operations and financial results are included in reports
on file with Canadian securities regulatory authorities, including the Company’s Annual Information Form, and may be accessed
through the SEDAR website (www.sedar.com), or at the Company’s website (www.deethree.ca). Furthermore, the forward-looking
statements contained in this MD&A are made as of the date of this MD&A 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. The Company’s forward-looking statements are expressly
qualified in their entirety by this cautionary statement.
Non-IFRS Measurements
This MD&A contains the terms “funds from (used in) operations” and “funds from (used in) operations per share”, which should not
be considered an alternative to or more meaningful than cash flow from (used in) operating activities as determined in accordance
with IFRS. These terms do not have any standardized meaning as prescribed by IFRS. DeeThree’s determination of funds from
(used in) operations and funds from (used in) operations per share may not be comparable to that reported by other companies.
Management uses funds from (used in) operations to analyze operating performance and leverage, and considers funds from
(used in) operations to be a key measure as it demonstrates the Company’s ability to generate cash necessary to fund future
capital investments and to repay debt, if applicable. Funds from (used in) operations is calculated using cash flow from (used in)
operating activities as presented in the statement of cash flows, before changes in non-cash working capital. DeeThree presents
funds from (used in) operations per share whereby per share amounts are calculated using weighted-average shares outstanding,
consistent with the calculation of earnings per share.
The following table reconciles funds from operations with cash flow from operating activities, which is the most directly comparable
measure calculated in accordance with IFRS:
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Cash flow from operating activities
Changes in non-cash working capital
30,978
(14,747)
754
3,340
62,292
(16,204)
7,100
4,733
Funds from operations
16,231
4,094
46,088
11,833
(000s)
During the three months and year ended December 31, 2012, the Company’s funds from operations totalled $16,231,000 ($0.23
per basic share and $0.22 per diluted share) and $46,088,000 ($0.69 per basic share and $0.68 per diluted share), respectively,
versus $4,094,000 ($0.06 per basic and diluted share) and $11,833,000 ($0.21 per basic and diluted share) in the respective
periods of 2011.
28
DeeThree Exploration Ltd.
The Company considers corporate netbacks to be a key measure as they demonstrate DeeThree’s profitability relative to current
commodity prices. Corporate netbacks are comprised of operating, funds flow and net income (loss) netbacks. Operating netback
is calculated as the average sales price of the Company’s commodities, less royalties, operating costs and transportation expenses.
Funds flow netback starts with the operating netback and further deducts general and administrative costs and finance expense,
and then adds finance income as well as realized gains on financial instruments. To calculate the net income (loss) netback,
DeeThree takes the funds flow netback and deducts share-based compensation expense as well as depletion and depreciation
charges, accretion expense, unrealized gains or losses on financial instruments, any impairment or exploration and evaluation
expense and deferred income taxes. No IFRS measure is reasonably comparable to netbacks. See “Netbacks (per unit)” for the
netback calculations.
Net debt and working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial
instruments, are used to assess efficiency, liquidity and the Company’s general financial strength. No IFRS measure is reasonably
comparable to net debt or working capital (deficit).
Other Measurements
All financial figures are in Canadian dollars. Where amounts are expressed on a barrel of oil equivalent (boe) basis, natural gas
volumes have been converted to oil equivalence at 6,000 cubic feet of gas to 1 barrel of oil. This conversion ratio of 6:1 is based
on an energy-equivalent conversion for the individual products, primarily applicable at the burner tip, and does not represent a
value equivalency at the wellhead. Such disclosure of boes may be misleading, particularly if used in isolation. Readers should be
aware that historical results are not necessarily indicative of future performance.
Forward-Looking Statements
Certain statements in this MD&A may constitute forward-looking statements. These statements relate to future events or the
Company’s future performance. All statements other than statements of historical fact may be forward-looking statements.
Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”,
“estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and
similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual
results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the
expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations
will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon by investors.
These statements speak only as of the date of this MD&A and are expressly qualified, in their entirety, by this cautionary statement.
In particular, this MD&A contains forward-looking statements pertaining to the following: projections of market prices and costs,
supply and demand for natural gas and crude oil, the quantity of reserves, natural gas and crude oil production levels, capital
expenditure programs, treatment under governmental regulatory and taxation regimes, and expectations regarding the Company’s
ability to raise capital and to continually add to reserves through acquisitions and development.
With respect to forward-looking statements in this MD&A, the Company has made assumptions regarding, among other things,
the legislative and regulatory environments of the jurisdictions where the Company carries on business or has operations, the
impact of increasing competition and the Company’s ability to obtain additional financing on satisfactory terms.
The Company’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the
risk factors discussed in this MD&A such as: volatility in the market prices for natural gas and crude oil; uncertainties associated with
estimating reserves; geological, technical, drilling and processing problems; liabilities and risks, including environmental liabilities
and risks inherent in natural gas and crude oil operations; incorrect assessments of the value of acquisitions; and competition for,
among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel. In addition, test results are not
necessarily indicative of long-term performance or of ultimate recovery.
2012 Annual Report
29
This forward-looking information represents the Company’s views as of the date of this MD&A and such information should not be
relied upon as representing its views as of any subsequent date. DeeThree has attempted to identify important factors that could
cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by
the forward-looking information. There may be other factors, however, that cause results, performance or achievements not to
be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current
expectations. There can be no assurance that forward-looking information will prove to be accurate, as results and future events
could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on
forward-looking information. The Company disclaims any intention or obligation to update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise, except as expressly required by applicable securities legislation.
Description of the Company
DeeThree is a Calgary, Alberta-based resource company actively engaged in light crude oil and natural gas exploration, development
and production in key areas of the Western Canada Sedimentary Basin. DeeThree commenced operations in 2007 as a private
company focused on creating long-term shareholder value through prudent operational and financial management.
DeeThree has created a platform for growth through a sound business strategy that includes low-risk development and exploration
as well as strategic acquisitions. The Company has two core operating areas: the Brazeau area of west central Alberta, which is
prospective for crude oil, natural gas and natural gas liquids, and the Ferguson area of southern Alberta, which features Bakken oil
plus shallow natural gas. These two core areas, along with the other non-core areas, have provided the Company with a balanced
and diverse production base.
Common shares of DeeThree are listed for trading on the Toronto Stock Exchange under the symbol DTX and on the United States
OTCQX under the symbol DTHRF.
In late 2008, DeeThree completed its first significant acquisition from a major oil and natural gas producer of properties in the
Lethbridge area of southern Alberta, which became known as the Ferguson area. Ferguson was the Company’s primary focus
until late in the first quarter of 2011 when DeeThree closed a transformational acquisition of properties in the Peace River Arch
and Brazeau areas. In this acquisition, which closed on March 22, 2011 (effective January 1, 2011), the Company acquired
approximately 1,830 boe/d of primarily high-working-interest, operated crude oil, natural gas and NGLs production and reserves,
of which approximately 40 percent was crude oil and NGLs.
First Quarter 2012 Transactions
In February 2012, the Company received payment of $1,000,000 as proceeds from the default on a farm-out agreement entered
into during 2011. Details of the farm-out are included in the December 31, 2011 MD&A.
On March 27, 2012, the Company issued 3,834,100 flow-through shares at a price of $4.50 per flow-through share for total
gross proceeds of $17,253,450 ($16,012,450 net of estimated share issuance expenses), including 500,100 flow-through shares
($2,250,450) issued on the exercise in full of the underwriters’ over-allotment option. The proceeds of the flow-through share
offering are being used to conduct exploration activity on the Company’s properties.
Second Quarter 2012 Transactions
In April 2012, the Company’s lender approved an increase to the Company’s credit facility from $50,000,000 to $60,000,000.
Third Quarter 2012 Transactions
There were no significant transactions during the quarter ended September 30, 2012.
Fourth Quarter 2012 Transactions
In October 2012, the Company completed the funding of a new $90,000,000 revolving demand credit facility. The new credit
facility is provided by a syndicate of two new lenders replacing and paying out DeeThree’s previous revolving demand credit facility.
On October 4, 2012, the Company executed a purchase and sale agreement with a private oil and natural gas company pursuant
to which DeeThree acquired interests in producing assets in the Brazeau area for total consideration of $7,457,000 subject to
certain adjustments.
30
DeeThree Exploration Ltd.
On October 18, 2012, the Company issued 3,139,500 common shares at a price of $5.50 per common share, including 409,500
common shares ($2,252,250) issued on the exercise in full of the underwriters’ over-allotment option and 770,000 flow-through
shares at a price of $6.50 per flow-through share, for total gross proceds of $22,272,250 ($20,658,500 net of estimated share
issuance expenses). The proceeds are being used to conduct development and exploration activity of the Company’s Belly River
targets at Brazeau as well as additional Upper Bakken targets at Ferguson.
Also during the fourth quarter of 2012, DeeThree entered into a farm-in agreement with a senior oil and natural gas producer
pursuant to which it may earn 100 percent working interest in up to 34 additional sections of Belly River petroleum and natural gas
rights directly offsetting DeeThree’s Brazeau property. DeeThree is committed to drilling a minimum of three horizontal wells on the
farm-in lands with a continuing rolling option thereafter in return for a 15 percent non-convertible overriding royalty.
Subsequent Events
On January 18, 2013, the Company executed a purchase and sale agreement with an oil and natural gas company pursuant to
which DeeThree acquired interests in producing assets in the Peace River Arch area for consideration of approximately $2,100,000
subject to certain adjustments.
On February 19, 2013, the Company issued 4,420,000 common shares at a price of $6.80 per share for total gross proceeds
of $30,056,000 ($27,952,000 net of estimated share issuance expenses). The proceeds will be used to conduct development
activity at Ferguson and Brazeau.
On March 12, 2013, the Company issued 663,000 common shares at $6.80 per share for total gross proceeds of $4,508,400
($4,192,800 net of estimated share issuance expenses) on the exercise in full of the underwriters’ over-allotment option from the
February issuance.
Financial and Operating Results
Sales Volumes
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
Sales
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLs (bbls/d)
9,377
3,511
259
7,714
957
161
8,902
2,472
267
6,974
561
137
Total sales (boe/d)
5,333
2,403
4,223
1,860
(%)
(%)
(%)
(%)
29
66
5
54
40
6
35
59
6
63
30
7
100
100
100
100
Production Split
Natural gas
Crude oil
NGLs
Total
For the fourth quarter of 2012, the Company’s production averaged 5,333 boe/d compared to 2,403 boe/d in the same period
of 2011 and 4,692 boe/d in the third quarter of 2012. This represents a 122 percent year-over-year and 14 percent quarter-overquarter increase, directly attributable to the Company’s drilling success.
For the year ended December 31, 2012, DeeThree’s production averaged 4,223 boe/d compared to 1,860 boe/d in 2011,
representing a 127 percent increase. During 2012, production was comprised of 8,902 mcf/d of natural gas, 2,472 bbls/d of crude
oil and 267 bbls/d of NGLs, thereby increasing the Company’s crude oil and NGLs production to 65 percent of total corporate
production versus 37 percent a year earlier.
2012 Annual Report
31
Revenue
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Natural gas
Crude oil
NGLs and other
2,915
24,181
1,282
2,439
8,287
1,147
8,193
70,936
5,983
9,454
19,221
4,072
Total oil and natural gas revenue
28,378
11,873
85,112
32,747
(000s)
During the three months ended December 31, 2012, revenue increased by 139 percent to $28,378,000 from $11,873,000 in the
comparative period of 2011, and rose by 18 percent from $24,020,000 in the third quarter of 2012. These increases were a result
of increased production compounded by the shift to a higher percentage of oil and NGLs (71% versus 46% and 68%, respectively)
and the resulting increase in corporate average price per boe.
During 2012, revenue totalled $85,112,000 versus $32,747,000 a year earlier. Total revenue increased by 160 percent over 2011
primarily as a result of the 122 percent year-over-year increase in sales volumes.
Commodity Prices and Foreign Exchange
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Benchmark Prices
Natural gas
NYMEX (US$/mmbtu) (1)
AECO (Cdn$/GJ) (2)
Crude oil
WTI (US$/bbl)
Edmonton light (Cdn$/boe)
3.37
3.05
3.62
3.01
2.80
2.26
4.07
3.43
88.18
84.16
94.06
97.59
94.21
86.35
95.12
95.22
Average Realized Prices
Natural gas ($/mcf)
Crude oil ($/bbl)
NGLs ($/bbl)
3.38
74.86
51.43
3.44
94.17
73.73
2.51
78.40
59.78
3.71
94.37
77.35
Combined average ($/boe)
57.83
53.70
55.07
48.23
0.99
1.01
1.02
0.98
1.00
1.00
0.99
1.01
Foreign Exchange
Cdn$/US$
US$/Cdn$
(1)
(2)
Mmbtu is the abbreviation for millions of British thermal units. One mcf of natural gas is approximately 1.02 mmbtu.
GJ is the abbreviation for gigajoule. One mcf of natural gas is approximately 1.05 GJ.
The Company’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials and
foreign exchange rates. The Company seeks to protect itself from fluctuations in prices and exchange rates by maintaining an
appropriate hedging strategy. As at the date of this MD&A, DeeThree had five crude oil hedges in place (see “Risk Management”
below for details), one of which was entered into during 2011 and four of which were entered into during 2012. Most commodity
prices are based on U.S. dollar benchmarks, which result in the Company’s realized prices being influenced by the Canadian/U.S.
exchange rates. The Company does not sell or transact in foreign currency, but may be affected by foreign currency exchange
rate changes related to commodity prices as outlined above. As at the date of this MD&A, DeeThree also had two foreign currency
exchange risk management contracts in place to mitigate these risks (see “Risk Management” below for contract details), one of
which was entered into during 2011 and one of which was entered into during 2012.
32
DeeThree Exploration Ltd.
During the three-month period ended December 31, 2012, benchmark natural gas prices in Canada were consistent with the
same period in 2011. In Canada, the benchmark index is the price set at the AECO hub, a major storage site near the TransCanada
Energy pipeline exit point from Alberta at Empress. The benchmark index for United States natural gas prices is the market price
as established by the New York Mercantile Exchange at Henry Hub (NYMEX), a major point of natural gas pipeline intersection
in Louisiana. NYMEX is linked to AECO through transportation tariffs from the respective hubs to common markets and through
foreign exchange rates. AECO prices averaged $3.05/GJ throughout the last quarter of 2012 compared to $3.01/GJ in the fourth
quarter of 2011 and $2.17/GJ in the third quarter of 2012. DeeThree’s average realized natural gas price during the three-month
period was $3.38/mcf in the fourth quarter of 2012 versus $3.44/mcf a year earlier and $2.38/mcf in the third quarter of 2012.
Oil prices decreased slightly in the fourth quarter of 2012 with West Texas Intermediate (WTI) averaging $88.18/bbl compared to
$94.06/bbl in the same period of 2011 and $92.22/bbl in the third quarter of 2012. The benchmark for crude oil prices in North
America, and widely quoted globally, is WTI delivered to Cushing, Oklahoma, again as determined by the NYMEX. Canadian
crude prices are based on refiner postings in Canadian dollars at Edmonton, Alberta and, as with natural gas, are linked to WTI
through transportation tariffs to common markets and the foreign exchange rate. The average realized price of DeeThree’s crude
oil was $74.86/bbl for the fourth quarter of 2012 compared to $94.17/bbl a year earlier and $76.22/bbl in the third quarter of
2012. Crude oil prices were down overall in 2012, as a result of widening Canadian crude differentials. The volatility in Canadian
crude oil differentials is primarily attributed to increased North American oil production, refinery outages and pipeline infrastructure
bottlenecks. DeeThree’s realized prices for crude oil production are also affected by different quality adjustments in each of the
Company’s core operating areas. As the percentage of the Company’s total oil production from each of those areas changes,
the overall average realized price is affected. During the fourth quarter of 2012, the change in composition resulted in a greater
price differential from WTI than in the prior quarter and the fourth quarter of 2011. Information regarding the Company’s risk
management program can be found in “Business Risks and Risk Mitigation” below.
Royalties
Three Months Ended December 31,
Oil and natural gas revenues (000s)
Total royalties (000s)
Total royalties ($/boe)
Percent of revenue (%)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
28,378
5,735
11,873
2,452
85,112
15,670
32,747
6,056
11.69
20
11.09
21
10.14
18
8.92
18
The Ferguson property is primarily subject to freehold royalties, which consist of a sliding-scale royalty determined monthly on a
well-by-well basis using a calculation that is based on the New Alberta Crown Royalty 2009 with a cap of 30 percent. The sliding
scale varies based on productivity (a higher royalty is payable from wells with higher production rates) and commodity prices (a
higher royalty is payable in times of higher natural gas and crude oil prices).
The Brazeau property is primarily subject to Crown royalties payable to the provincial government and overriding royalties on oil,
natural gas and NGLs production. These types of royalties are also sensitive to production levels and commodity prices; therefore,
the Company’s royalties will continue to fluctuate with commodity prices, well production rates, production declines of existing
wells along with performance and location of new wells drilled.
For the fourth quarter of 2012, royalties totalled $5,735,000 or 20 percent of revenue compared to $2,452,000 or 21 percent of
revenue for the same quarter in 2011 and $3,785,000 or 16 percent of revenue in the third quarter of 2012. The year-over-year
royalty rate change was primarily due to new production from the Company’s wells brought on-stream during the past year, some
of which are subject to a freehold royalty based on the New Alberta Crown Royalty 2009, while others qualify for the 5 percent
royalty holiday under the Government of Alberta royalty framework.
During the year ended December 31, 2012, royalties totalled $15,670,000 or 18 percent of revenue versus $6,056,000 or
18 percent of revenue a year earlier.
2012 Annual Report
33
Operating and Transportation Expenses
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Operating expenses
Transportation expenses
3,951
893
3,950
455
16,272
2,692
9,724
1,071
Total
4,844
4,405
18,964
10,795
Operating expenses ($/boe)
Transportation expenses ($/boe)
8.05
1.82
17.87
2.06
10.53
1.74
14.32
1.58
Total ($/boe)
9.87
19.93
12.27
15.90
(000s except per boe)
Operating costs include all costs associated with the production of crude oil and natural gas. The major components of operating
costs include charges for contract operating, processing fees, lease rentals, property and pipeline taxes, utilities and well
maintenance charges.
Operating expenses for the fourth quarter of 2012 totalled $3,951,000 or $8.05/boe compared to $3,950,000 or $17.87/boe in
the same period of 2011 and $4,243,000 or $9.83/boe in the third quarter of 2012. As production volumes increase, the Company
has realized economies of scale at Ferguson and Brazeau, contributing to a lower operating cost per unit of production.
Transportation expenses for the three months ended December 31, 2012 were $893,000 or $1.82/boe compared to $455,000
or $2.06/boe in the fourth quarter of 2011 and $806,000 or $1.87/boe in the third quarter of 2012. Transportation expenses
reflect NOVA and ATCO transportation costs and fluctuate depending on the proportion of the Company’s natural gas that flows
on firm service versus interruptible service (interruptible service is slightly more expensive) as well as the proportion of Company
volumes on ATCO versus NOVA (ATCO is less expensive). Over the past year, the Company has increased production of crude oil
and NGLs, and the transportation costs associated with those products consist primarily of pipeline tariffs, terminal charges and
trucking (crude oil and NGLs incur a higher cost per boe for transportation than natural gas).
For the year ended December 31, 2012, the Company incurred operating expenses of $16,272,000 or $10.53/boe compared to
$9,724,000 or $14.32/boe in 2011. Transportation expenses for the year totalled $2,692,000 or $1.74/boe versus $1,071,000 or
$1.58/boe last year.
Risk Management
The Company has elected not to use hedge accounting and, accordingly, the fair value of the financial contracts is recorded at
each period-end. The fair value may change substantially from period to period depending on commodity and foreign exchange
forward strip prices for the financial contracts outstanding at the balance sheet date. The change in fair value from period-end to
period-end is reflected in the earnings for that period. As a result, earnings may fluctuate considerably based on the period-ending
commodity and foreign exchange forward strip prices.
34
DeeThree Exploration Ltd.
As at December 31, 2012, the Company had the following crude oil and foreign exchange risk management contracts with a total
mark-to-market asset value of $850,000:
Period
Commodity
Type of Contract
Quantity
Pricing Point
Contract Price
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI-NYMEX
US$85.00/bbl (floor) –
US$111.00/bbl (cap) (1)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI-NYMEX
US$90.00/bbl (floor) –
US$113.25/bbl (cap) (2)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI-NYMEX
US$90.00/bbl (floor) –
US$116.25/bbl (cap) (3)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI-NYMEX
US$95.00/bbl (floor) –
US$118.00/bbl (cap) (4)
Jan. 1/13 – Dec. 31/13
Crude Oil
Swap
500 bbls/d
WTI-NYMEX
US$90.00/bbl (floor) –
US$106.00/bbl (cap) (5)
(1)
(2)
(3)
(4)
(5)
Unless the monthly WTI price averages over US$111.00/bbl every day for the entire month, in which case the cap becomes US$90.00/bbl.
Unless the monthly WTI price averages over US$113.25/bbl every day for the entire month, in which case the cap becomes US$92.00/bbl.
Unless the monthly WTI price averages over US$116.25/bbl every day for the entire month, in which case the cap becomes US$92.00/bbl.
Unless the monthly WTI price averages over US$118.00/bbl every day for the entire month, in which case the cap becomes US$100.00/bbl.
Unless the monthly WTI price averages over US$106.00/bbl every day for the entire month, in which case the cap becomes US$90.00/bbl.
Period
Pricing Point
(Cdn$/US$)
Currency
Type of Contract
Quantity
Jan.1/12 – Dec. 31/13
US$
Average Rate Range
Bonus Accumulator
US$700,000
Target – $1.10
Cdn$/US$ + $1,000
bonus/day (1)
June 1/12 – Dec. 31/13
US$
Average Rate Range
Bonus Accumulator
US$900,000
Target – $1.0775
Cdn$/US$ + $900
bonus/day (2)
(1) The
Company can earn a bonus payout of up to $1,000 per day depending on the period in which the exchange rate remains in the applicable range of equal to or
greater than $0.9350 and equal to or less than $1.10.
(2) The Company can earn a bonus payout of up to $900 day depending on the period in which the exchange rate remains in the applicable range of equal to or
greater than $0.9300 and equal to or less than $1.0775.
These contracts are considered to be financial instruments and the resulting derivative financial asset was recorded on the
Company’s statement of financial position, with the unrealized gain or loss being recorded on the statement of operations and
comprehensive income (loss).
Three Months Ended December 31,
Unrealized loss (gain) on financial instruments (000s)
Unrealized loss (gain) on financial instruments ($/boe)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
818
1.67
3,040
13.75
(1,879)
(1.22)
1,027
1.51
During the three months and year ended December 31, 2012, the Company also realized a gain on these financial instruments as
a result of commodity prices and foreign exchange rates in relation to the contract terms.
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Realized gain on financial instruments (000s)
(622)
(62)
(1,621)
(206)
Realized gain on financial instruments ($/boe)
(1.27)
(0.28)
(1.05)
(0.30)
2012 Annual Report
35
G&A Expense
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Gross G&A expense
Capitalized G&A (direct)
Overhead recoveries
2,466
(632)
(302)
1,664
(389)
(267)
6,974
(1,639)
(984)
5,683
(884)
(387)
G&A expense (net)
Transaction costs
1,532
(42)
1,008
(20)
4,351
(57)
4,412
(1,178)
G&A expense (net)
G&A expense (net) ($/boe)
1,490
3.04
988
4.47
4,294
2.78
3,234
4.76
(000s except per boe)
Gross G&A expense totalled $2,466,000 for the three-month period ended December 31, 2012 compared to $1,664,000 in the
comparable period of 2011 and $1,437,000 in the third quarter of 2012. Net G&A costs were $1,490,000 or $3.04/boe in the
fourth quarter of 2012 compared to $988,000 or $4.47/boe a year earlier and $781,000 or $1.81/boe in the third quarter of 2012.
When compared to the same quarter of the prior year, gross G&A costs increased on an absolute basis due to increased staffing
costs (including salaries, bonuses and office rent) associated with higher activity levels. In the last quarter of 2012, the Company
had an average of 20 full-time employees and eight consultants versus 13 full-time employees and two consultants in the same
period of 2011.
The Company capitalized direct G&A expenses amounting to $632,000 and had overhead recoveries of $302,000 in the fourth
quarter of 2012 versus $389,000 and $267,000, respectively, in the comparative period of 2011, and $254,000 and $402,000,
respectively, in the third quarter of 2012.
G&A net expense for the year ended December 31, 2012 totalled $4,294,000 or $2.78/boe compared to $3,234,000 or $4.76/
boe in 2011. During the year ended December 31, 2012, the Company capitalized $1,639,000 in direct costs relating to its
exploration and development efforts and $984,000 of overhead recoveries compared to $884,000 and $387,000, respectively, in
2011. G&A expense per unit of production fell by 42 percent year-over-year due to the Company’s significant production growth.
Share-Based Compensation
Three Months Ended December 31,
(000s except per boe)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Gross share-based compensation
Share-based compensation
reclassified to operating costs
Capitalized share-based compensation
653
552
2,994
1,654
(22)
(215)
(19)
(216)
(106)
(1,065)
(48)
(576)
Share-based compensation expense (net)
Share-based compensation expense (net) ($/boe)
416
0.85
317
1.43
1,823
1.18
1,030
1.52
The Company has a stock option plan, which is described in note 10 to the financial statements for the years ended
December 31, 2012 and 2011. Options granted under the plan have a four-year vesting term and expire five years from the grant
date. The fair value of options granted is estimated at the grant date using the Black-Scholes option-pricing model. Share-based
compensation expense is a non-cash expense that reflects the amortization over the vesting period of the fair value of stock
options granted to the Company’s employees, consultants and directors. For those stock options granted to field employees,
their portion of the share-based compensation is reclassified to operating expenses to be consistent with the recognition of their
salaries on the statement of operations and comprehensive loss.
36
DeeThree Exploration Ltd.
For the quarter ended December 31, 2012, the Company incurred a net expense of $416,000 or $0.85/boe versus $317,000
or $1.43/boe in the same period of 2011 and $468,000 or $1.08/boe in the third quarter of 2012. This year-over-year absolute
increase was directly attributable to increased staffing.
During 2012, DeeThree incurred a net expense of $1,823,000 or $1.18/boe compared to $1,030,000 or $1.52/boe recorded in 2011.
Depletion and Depreciation (D&D)
Three Months Ended December 31,
D&D provision (000s)
D&D provision ($/boe)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
9,786
19.94
5,305
23.99
31,264
20.23
14,892
21.93
D&D is computed on a unit-of-production basis. Such expense, on a boe basis, fluctuates from period to period primarily as a
result of changes in the underlying proved plus probable reserves base and in the amount of costs subject to D&D, including future
development costs. Such costs are segregated and depleted on an area-by-area basis relative to the respective underlying proved
plus probable reserves base.
Depreciation is provided on certain field facilities using the straight-line method over a 20-year useful life and on office assets using
the declining balance method at rates of 20-30 percent.
The Company’s D&D expense for the three months ended December 31, 2012 was $9,786,000 or $19.94/boe compared to
$5,305,000 or $23.99/boe in the comparable period of 2011 and $8,628,000 or $19.99/boe in the third quarter of 2012. Depletion
and depreciation expense for the fourth quarter of 2012 increased over the same period of 2011 primarily due to higher production
volumes and an increase in the rate per barrel as a result of higher estimated future development costs of the Ferguson and
Brazeau properties. The future development costs are a key element of the rate determination.
The year-over-year absolute increase was attributable to the increased production as a result of the Company’s drilling program.
The year-over-year per unit depletion amounts decreased due to the fact that successful 2012 wells were added to the asset base
at a lower cost per boe of new reserves than the assets purchased in the March 2011 acquisition, which contributes to a lower
D&D rate overall.
In 2012, D&D expense totalled $31,264,000 or $20.23/boe compared to $14,892,000 or $21.93/boe recorded in 2011.
Impairment
Under International Accounting Standard (IAS) 36 – “Impairment of Assets”, impairment testing is performed at the cash-generating
unit (CGU) level and is a one-step process for testing and measuring impairment of assets in which each CGU’s carrying value is
compared to the higher of value in use and fair value less costs to sell. Impairment testing is required when there are indicators of
impairment such as a significant drop in commodity prices or a write-down of proved or probable reserves. At December 31, 2012,
as a result of decreasing natural gas prices, the Company performed an impairment test on one of the CGUs primarily based on
the net present value of cash flows from oil and natural gas reserves of that CGU at an appropriate discount rate. For the year
ended December 31, 2012, there were no impairment issues and, as such, no impairment was recorded.
2012 Annual Report
37
Exploration and Evaluation (E&E) Expense
Three Months Ended December 31,
E&E expense (000s)
E&E expense ($/boe)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
323
0.66
7,322
33.12
3,068
1.99
7,987
11.76
Under IFRS, DeeThree accumulates those costs related to E&E assets in one cost pool, pending determination of technical
feasibility and commercial viability of the asset. E&E costs are primarily for seismic data, undeveloped land and drilling until the well
in question is complete and results have been evaluated. Costs related to wells determined to be uneconomical as well as costs
of undeveloped land lease expiries are expensed as they occur.
During the fourth quarter of 2012, the Company recorded E&E expense of $323,000 or $0.66/boe, which related to lease expiries
in several of the Company’s areas as well as a write-off of preliminary drilling costs, versus $7,322,000 or $33.12/boe in the same
period of 2011, mostly related to the write-off of costs incurred for dry and abandoned wells, and $225,000 or $0.52/boe in the
third quarter of 2012 related to lease expiries.
During the year ended December 31, 2012, the Company recorded E&E expense of $3,068,000 or $1.99/boe versus $7,987,000
or $11.76/boe in 2011. The year-over-year decrease is due to the fact that DeeThree did not have any dry and abandoned wells
during 2012, as compared to three such wells in the prior year, which contributed significantly to that year’s E&E expense.
Accretion and Finance Expenses
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Accretion expense on
decommissioning liabilities
Finance expense
80
680
75
4
354
1,766
234
118
Total accretion and finance expenses
760
79
2,120
352
Accretion expense on
decommissioning liabilities ($/boe)
Finance expense ($/boe)
0.16
1.39
0.34
0.02
0.23
1.14
0.34
0.17
Total accretion and finance expenses ($/boe)
1.55
0.36
1.37
0.51
(000s except per boe)
Accretion expense represents the increase in the present value of the Company’s decommissioning liabilities. In the fourth quarter of
2012, the Company recorded accretion expense of $80,000 or $0.16/boe compared to $75,000 or $0.34/boe in the same period
of 2011 and $82,000 or $0.19/boe in the third quarter of 2012. The absolute increase is primarily due to the decommissioning
liabilities added for the 2012 wells drilled. However, the expense per boe decreased as a function of several things: first, as
accretion is not a unit-based calculation, increased production volumes have spread the expense over a larger number of barrels;
second, during the year the Company revised the discount rate used to calculate the liability, first from 3.5 percent to 2.5 percent
in the third quarter and then again to 2.25 percent in the fourth quarter based on estimated market interest rates. This resulted in a
revision to the decommissioning liability of $1,237,000 during the second half of the year and will result in lower accretion charges
in each period going forward. The underlying liability may increase over time based on new obligations incurred from drilling wells,
constructing facilities, acquiring operations, adjusting future estimates of timing or estimated decommissioning costs. The liability
can also be reduced as a result of abandonment work actually completed.
38
DeeThree Exploration Ltd.
During the three months ended December 31, 2012, the Company recorded finance expenses of $680,000 or $1.39/boe
compared to $4,000 or $0.02/boe in the same period of 2011 and $560,000 or $1.30/boe in the third quarter of 2012. The
Company incurred interest charges and standby fees related to the $90,000,000 credit facility (2011 – $20,000,000), which was
drawn to $63,104,000 at the end of the year.
During 2012, the Company recorded accretion expense of $354,000 or $0.23/boe versus $234,000 or $0.34/boe in 2011 and
finance expenses of $1,766,000 or $1.14/boe in 2012 versus $118,000 or $0.17/boe in 2011.
Income Taxes
Three Months Ended December 31,
Deferred income tax expense (recovery) (000s)
Deferred income tax expense (recovery) ($/boe)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
1,303
2.66
(2,654)
(12.00)
4,171
2.70
(812)
(1.20)
During the fourth quarter of 2012, the Company recorded a deferred income tax expense of $1,303,000 or $2.66/boe compared
to a recovery of $2,654,000 or $12.00/boe in same period of 2011 and expense of $1,001,000 or $2.32/boe in the third quarter
of 2012. The fourth quarter expense was primarily related to an increase in the taxable base of the oil and natural gas assets offset
by a change to the non-capital loss provision from the prior year. The movement in the taxable base of oil and natural gas assets
is due to the Company’s capital spending associated with flow-through shares. As costs are incurred, the Company reverses
the flow-through share liability and recognizes the deferred income tax expense at that time. During the three months ended
December 31, 2012, the Company spent approximately $160,000 in eligible capital expenditures related to the March 2012
issuance of flow-through shares.
DeeThree does not have current income taxes payable and does not expect to pay current income taxes in 2013 as the Company
had estimated tax pools available at December 31, 2012 of $281,000,000.
Funds from Operations
Three Months Ended December 31,
(000s)
Net income (loss)
Non-cash items:
D&D
Deferred income tax (recovery)
Share-based compensation (1)
Accretion
Unrealized loss (gain) on financial instruments
E&E expense
Funds from operations
(1)
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
3,483
(9,330)
7,181
(12,573)
9,786
1,303
438
80
818
323
5,305
(2,654)
336
75
3,040
7,322
31,264
4,171
1,929
354
(1,879)
3,068
14,892
(812)
1,078
234
1,027
7,987
16,231
4,094
46,088
11,833
The share-based compensation amount included in the calculation of funds from operations has been adjusted for the non-cash portion related to certain field
employees that was reclassified to operating expenses for presentation in the statement of operations and comprehensive income (loss).
During the three months ended December 31, 2012, the Company generated funds from operations totalling $16,231,000 or $0.23
per basic share and $0.22 per diluted share compared to $4,094,000 or $0.06 per basic and diluted share in the comparative
period of 2011 and $14,265,000 or $0.21 per basic share and $0.20 per diluted share in the third quarter of 2012. This 296
percent year-over-year increase was primarily due to increased revenue from production, partially offset by increased royalties and
operating and transportation costs.
Funds from operations totalled $46,088,000 or $0.69 per basic share and $0.68 per diluted share for the year ended
December 31, 2012 compared to $11,833,000 or $0.21 per basic and diluted share recorded in 2011.
2012 Annual Report
39
Net Income (Loss)
For the three months ended December 31, 2012, the Company recorded net income of $3,483,000 or $0.05 per basic and diluted
share compared to a net loss of $9,330,000 or $0.15 per basic and diluted share in the same period of 2011 and net income of
$1,294,000 or $0.02 per basic and diluted share in the third quarter of 2012. The Company’s positive net income for the quarter
was primarily due to increased production, leading to increased revenues in the period, compounded by decreasing royalties and
operating expenses on a per barrel basis.
Net income for the year ended December 31, 2012 was $7,181,000 or $0.11 per basic and diluted share versus a net loss of
$12,573,000 or $0.22 per basic and diluted share in 2011.
Netbacks (per unit)
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($/boe)
($/boe)
($/boe)
($/boe)
Average sales price
Royalties
Operating
Transportation
57.83
(11.69)
(8.05)
(1.82)
53.70
(11.09)
(17.87)
(2.06)
55.07
(10.14)
(10.53)
(1.74)
48.23
(8.92)
(14.32)
(1.58)
Operating netback (1)
G&A and other expense (excludes non-cash items) (2)
Realized gain on financial instruments
Finance income
Finance expenses
36.27
(3.12)
1.27
–
(1.39)
22.68
(4.56)
0.28
0.04
(0.02)
32.66
(2.82)
1.05
–
(1.14)
23.41
(6.50)
0.30
0.31
(0.17)
Funds flow netback (1)
D&D expense
Accretion
Share-based compensation
Unrealized gain (loss) on financial instruments
E&E expense
Deferred income tax recovery (expense)
33.03
(19.94)
(0.16)
(0.85)
(1.67)
(0.66)
(2.66)
18.42
(23.99)
(0.34)
(1.43)
(13.75)
(33.12)
12.00
29.75
(20.23)
(0.23)
(1.18)
1.22
(1.99)
(2.70)
17.35
(21.93)
(0.34)
(1.52)
(1.51)
(11.76)
1.20
7.09
(42.21)
4.64
(18.51)
Net income (loss) netback (1)
(1)
(2)
Non-IFRS measure; refer to the commentary at the beginning of this MD&A. Operating netback, funds flow netback and net income (loss) netback are calculated
by dividing operating income, funds flow from operations and net income (loss) by the sales volume in boe for the period then ended. For a description of the boe
conversion ratio, refer to “Other Measurements” at the beginning of this MD&A.
For the three months and year ended December 31, 2012, G&A and other expense includes transaction costs of $42,000 and $57,000, respectively, relating to
the acquisition of additional interests in the Brazeau area. For the three months and year ended December 31, 2011, G&A and other expense includes transaction
costs of $20,000 and $1,178,000, respectively, relating to the acquisition of the Peace River Arch and Brazeau properties.
The operating netback was $36.27/boe for the three months ended December 31, 2012 compared to $22.68/boe in the same
period of 2011 and $35.18/boe in the third quarter of 2012. As compared to the prior year’s fourth quarter, the Company
experienced a higher realized average price throughout the three months ended December 31, 2012. Even though each individual
product had a lower realized price in the period than in the same period of 2011, the higher realized average price and resulting
higher netback was largely the result of a shift to a proportionately higher oil production base, which attracts higher pricing. The
improved netback was also positively affected by decreased operating costs during the quarter.
For 2012, DeeThree achieved an operating netback of $32.66/boe versus $23.41/boe in the same period of 2011, again related
to higher pricing due to the higher crude oil weighting and decreased operating costs.
40
DeeThree Exploration Ltd.
Investment and Investment Efficiencies
Capital Expenditures and Acquisitions
Three Months Ended December 31,
Year Ended December 31,
2012
2011
2012
2011
($)
($)
($)
($)
Property acquisitions and adjustments
Drilling and completions
Equipment and facilities
Land and lease retention
Geological and geophysical
Capitalized G&A and other
7,457
24,192
10,147
2,645
33
660
21
14,161
3,911
831
1,117
488
7,457
101,858
22,298
11,242
202
1,696
125,979
49,480
5,949
3,921
1,150
1,078
Total capital expenditures
Land-for-shares transaction (1)
Farm-out proceeds
45,134
–
–
20,529
–
(3,000)
144,753
–
(1,000)
187,557
1,384
(8,000)
Total capital expenditures, net of farm-out proceeds
45,134
17,529
143,753
180,941
(000s)(excluding decommissioning liabilities
and capitalized share-based compensation)
(1)
In July 2011, the Company issued 400,000 common shares at a price of $3.46 per common share in exchange for approximately 12,800 net acres of undeveloped
land located primarily in the Peace River Arch area of Alberta. This was considered to be a non-cash capital expenditure, and as such, was presented separately
from the cash expenditures in the table above.
During the fourth quarter of 2012, the Company incurred a total of $45,134,000 (fourth quarter 2011 – $20,529,000) in capital
expenditures, excluding the non-cash decommissioning liabilities and capitalized share-based compensation. During the period,
the Company spent $7,457,000 (fourth quarter 2011 – $21,000) to complete an acquisition for additional working interests in
the Brazeau area. With the Company’s focus on drilling in the Ferguson and Brazeau areas, drilling and completion expenditures
totalled $24,192,000 in the fourth quarter of 2012 (fourth quarter 2011 – $14,161,000), including the drilling of eight gross (7.9 net)
wells. In the comparative quarter of 2011, the Company drilled seven gross (5.9 net) wells and incurred significant completion
expenditures. For the three months ended December 31, 2012, DeeThree spent $10,147,000 (fourth quarter 2011 – $3,911,000)
on tie-ins and facilities, which in 2012 consisted primarily of expenditures related to tie-in of the 2012 wells drilled as well as
continued construction of an amine plant and two oil battery sites at Ferguson. The Company spent $2,645,000 in the fourth
quarter of 2012 (fourth quarter 2011 – $831,000) on Crown land sales and $33,000 (fourth quarter 2011 – $1,117,000) related
to seismic programs. The remaining $660,000 in the fourth quarter of 2012 (fourth quarter 2011 – $488,000) was invested in
capitalized G&A and other corporate assets.
For the year ended December 31, 2012, capital expenditures totalled $144,753,000 versus $187,557,000 in 2011. A significant
portion of the 2011 capital spending was for the Peace River and Brazeau property acquisition, for consideration of $123,185,000
after certain adjustments. In 2012, as the Company’s focus shifted to drilling mainly at Brazeau and Ferguson, only $7,457,000
was spent on acquisitions. Drilling and completion expenditures totalled $101,858,000 in 2012 (2011 – $49,480,000), equipment
and facility costs were $22,298,000 (2011 – $5,949,000), land purchases totalled $11,242,000 (2011 – $3,921,000), $202,000
of spending related to seismic programs (2011 – $1,150,000) and the remaining $1,696,000 (2011 – $1,078,000) was invested
in capitalized G&A and other corporate assets. During 2012, the Company also received $1,000,000 as proceeds from a default
on a farm-out agreement entered into during the second quarter of 2011 (2011 – $5,000,000 as initial payment for the farm-out
and $3,000,000 default payment), which was recorded against E&E and slightly offset total capital expenditures for the period.
2012 Annual Report
41
Drilling Activity
Exploration
Total
Gross
Net
Gross
Net
Gross
Net
(#)
(#)
(#)
(#)
(#)
(#)
Three Months Ended
December 31, 2012
Natural gas
Crude oil and NGLs
Standing
Dry and abandoned
–
–
–
–
–
–
–
–
–
8
–
–
–
7.9
–
–
–
8
–
–
–
7.9
–
–
Total wells
–
–
8
7.9
8
7.9
Success rate (%)
Average working interest (%)
–
–
100
99
100
99
Three Months Ended
December 30, 2011
Natural gas
Crude oil and NGLs
Standing
Dry and abandoned
–
1
–
–
–
1.0
–
–
1
5
–
–
1.0
3.9
–
–
1
6
–
–
1.0
4.9
–
–
Total wells
1
1.0
6
4.9
7
5.9
Success rate (%)
Average working interest (%)
100
100
100
81
100
84
Year Ended
December 31, 2012
Natural gas
Crude oil and NGLs
Standing
Dry and abandoned
–
2
–
–
–
2.0
–
–
–
26
2
–
–
24.8
2.0
–
–
28
2
–
–
26.8
2.0
–
Total wells
2
2.0
28
26.8
30
28.8
Success rate (%)
Average working interest (%)
100
100
100
96
100
96
Year Ended
December 31, 2011
Natural gas
Crude oil and NGLs
Standing
Dry and abandoned
–
5
1
3
–
4.4
0.4
3.0
1
10
–
–
1.0
8.6
–
–
1
15
1
3
1.0
13.0
0.4
3.0
Total wells
9
7.8
11
9.6
20
17.4
Success rate (%)
Average working interest (%)
42
Developed
DeeThree Exploration Ltd.
67
87
100
88
85
87
During the fourth quarter of 2012, DeeThree drilled 6 gross (6.0 net) Bakken wells on its Ferguson property and 2 gross (1.9 net)
on its Brazeau property with a 100 percent success rate. During the three months ended December 31, 2011, the Company drilled
7 gross (5.9 net) wells for a 100 percent success rate, including 2 gross (1.8 net) horizontal Belly River wells in the Brazeau area,
2 gross (2.0 net) Bakken wells and 1 gross (1.0 net) Sunburst well in the Ferguson area, and 2 gross (1.1 net) horizontal wells in
the Peace River Arch area.
During the year ended December 31, 2012, DeeThree drilled 20 gross (20.0 net) wells at Ferguson, 9 gross (8.5 net) wells at
Brazeau and 1 gross (0.3 net) well at Rycroft for a 100 percent success rate on 30 gross (28.8 net) wells for the year, compared to
20 gross (17.4 net) wells in the Brazeau, Ferguson and Rycroft areas for an 85 percent success rate in 2011.
Land Holdings
The Company’s land holdings as at December 31, 2012 and 2011 were as follows:
Undeveloped
Developed
Total
Gross
Net
Gross
Net
Gross
Net
(acres)
(acres)
(acres)
(acres)
(acres)
(acres)
Lethbridge
Brazeau
Peace River Arch
Other
230,878
18,880
42,800
7,847
229,689
16,104
28,232
5,909
40,125
17,120
49,692
7,040
38,008
13,860
23,492
4,474
271,003
36,000
92,492
14,887
267,697
29,964
51,724
10,383
Total
300,405
279,934
113,977
79,834
414,382
359,768
2011
Lethbridge
Brazeau
Peace River Arch
Other
202,300
19,200
56,720
6,560
199,852
15,761
33,848
4,944
62,348
15,360
49,202
8,970
61,201
11,097
22,440
5,406
264,648
34,560
105,922
15,530
261,053
26,858
56,288
10,350
Total
284,780
254,405
135,880
100,144
420,660
354,549
2012
Liquidity and Capital Resources
Working Capital
The following table summarizes the change in working capital during the years ended December 31, 2012 and 2011:
Years Ended December 31,
(000s)
Working capital (deficit) – beginning of period
Abandonment and reclamation costs
Funds from operations
Issuance of capital stock for cash (net of share issuance expenses)
Capital expenditures
Acquisitions
Farm-out proceeds
Working capital deficit – end of period
2012
2011
($)
($)
(16,901)
(108)
46,088
37,088
(137,296)
(7,457)
1,000
28,505
(116)
11,833
122,434
(61,578)
(125,979)
8,000
(77,586)
(16,901)
2012 Annual Report
43
DeeThree entered 2012 with a working capital deficit of $16,901,000. In March 2012, the Company issued 3,834,100 flowthrough shares at a price of $4.50 per flow-through share for total gross proceeds of $17,253,450 ($16,012,450 net of estimated
share issuance expenses). The proceeds of the flow-through share offering are being used by the Company to conduct exploration
activity on its properties. Throughout 2012, the Company issued common shares on the exercise of options for total cash
proceeds of $417,000. In October 2012, the Company issued 3,139,500 common shares at a price of $5.50 per common share,
including 409,500 common shares ($2,252,250) issued on the exercise in full of the underwriters’ over-allotment option and
770,000 flow-through shares at a price of $6.50 per flow-through share for total gross proceeds of $22,272,250 ($20,658,500
net of estimated share issuance expenses). The proceeds of the share offering are being used to conduct development and
exploration activity on the Company’s Belly River prospects at Brazeau as well as additional Upper Bakken targets at Ferguson.
In 2012 the Company generated funds from operations of $46,088,000 and invested $137,296,000 in capital expenditures and
$7,457,000 in acquisitions for total capital spending of $144,753,000. The Company also received $1,000,000 as proceeds from
a farm-out agreement entered into during the second quarter of the prior year, which was recorded against E&E and modestly
offset the total capital expenditures for the period. DeeThree exited 2012 with a working capital deficit of $77,586,000.
At December 31, 2012, the Company had a revolving demand credit facility with an authorized borrowing base of $90,000,000
with interest charged at a rate per annum equal to the Canadian prime rate during the period in question, plus the applicable
margin, being a range of 0.50 percent to 2.50 percent, as determined by the Company’s debt to cash flow ratio. Standby fees
associated with this facility are charged based on an applicable margin, being a range of 0.2 percent to 0.45 percent per annum on
the undrawn portion of the facility, again based on the Company’s debt to cash flow ratio. Under this credit facility, the Corporation
is required to maintain a current ratio of not less than 1:1. As at December 31, 2012, $63,104,000 was drawn against the facility.
Collateral for this facility consists of a general security agreement, providing a security interest over all present and subsequently
acquired personal property, and a floating charge on all present and subsequently acquired land interests of the Company. The
facility is a subject to semi-annual review by the Company’s lender, with the next review scheduled for later in the spring of 2013.
DeeThree expects to fund future capital expenditures with its funds from operations and the unused demand credit facility.
Related-Party Transactions and Off-Balance-Sheet Transactions
The Company had the following related-party transactions during the year ended December 31, 2012:
The Company has retained a law firm to provide legal services. The Corporate Secretary of DeeThree is a partner of this firm. During
the year ended December 31, 2012, the Company incurred $570,000 with the firm (2011 – $475,000), which were included in G&A
expense and share issuance costs, of which $22,000 (2011 – $12,000) remained in accounts payable at December 31, 2012.
Services provided related to advice and counsel primarily in the areas of general legal, corporate governance and banking matters.
The Company expects to continue using the services of this firm in 2013.
All related-party transactions were in the normal course of operations and have been measured at exchange amounts established
and agreed to by the related parties and which are similar to those that the Company would expect to have negotiated with
unrelated third parties in similar circumstances.
There were no off-balance-sheet transactions entered into during the period nor are there any outstanding as at the date of
this MD&A.
44
DeeThree Exploration Ltd.
Contractual Obligations and Commitments
Years Ended December 31,
2013
2014
2015
2016+
Total
($)
($)
($)
($)
($)
Operating lease – office
Operating lease – equipment
Exploration expenditures (flow-through)
Drilling contracts
Bank debt
640
294
19,052
4,836
63,104
640
48
–
–
–
640
–
–
–
–
160
–
–
–
–
2,080
342
19,052
4,836
63,104
Total
87,926
688
640
160
89,414
(000s)
As at December 31, 2012, the Company had contractual obligations for its office leases totalling approximately $2,080,000
to March 2016. The head office lease obligations are comprised of the lease payments as well as parking and an estimate of
occupancy costs of the Company’s head office space. The Company also had contractual obligations for several vehicles and
equipment totalling approximately $342,000 to May 2014.
In connection with the issuance of flow-through shares by the Company during the first quarter of 2012, DeeThree is required to
spend $17,253,450 of eligible exploration expenditures by December 31, 2013. As at December 31, 2012, $3,206,000 of these
eligible exploration expenditures had been incurred. The remaining $14,047,450 of eligible expeditures will be incurred during
2013. These expenditures were renounced to shareholders in January 2013 effective December 31, 2012.
In connection with the Company’s issuance of flow-through shares during the fourth quarter of 2012, DeeThree is required to
spend an additional $5,005,000 of eligible exploration expenditures by December 31, 2013. As at December 31, 2012, $nil of
these expenditures had been incurred. These expenditures will be incurred during 2013 and were renounced to shareholders in
January 2013 effective December 31, 2012.
DeeThree has two contracts for drilling rig services under which the Company is committed to using services totalling $4,836,000
extending into late 2013.
At December 31, 2012, the Company also had the obligation to repay the amount outstanding on the revolving demand credit
facility, which was drawn to $63,104,000 at period-end.
During 2012, DeeThree entered into a farm-in agreement with a senior oil and natural gas producer pursuant to which it may
earn 100 percent working interest in up to 34 additional sections of Belly River petroleum and natural gas rights directly offsetting
DeeThree’s Brazeau property. DeeThree is committed to drilling a minimum of three horizontal wells on the farm-in lands, with a
continuing rolling option thereafter in return for a 15 percent non-convertible overriding royalty. As of the date of this MD&A, the
Company has drilled two of the horizontal wells related to this commitment.
2012 Annual Report
45
Share Capital
As at March 26, 2013, the Company had 76,167,745 common shares outstanding and 5,765,060 stock options outstanding.
Selected Quarterly Information (1)
Three Months Ended
Dec. 31,
Sept. 30,
2012
2012
2012
($)
($)
($)
Oil and natural gas revenues
28,378
Funds from (used in) operations 16,231
Per share – basic
0.23
Per share – diluted
0.22
Cash flow from (used in)
operating activities
30,978
Net income (loss)
3,483
Per share – basic
0.05
Per share – diluted
0.05
Total assets
329,666
Capital expenditures (2)
45,134
Working capital (deficit) (3)
(77,586)
Shareholders’ equity
212,090
24,020
14,265
0.21
0.20
(000s, except per share amounts
and production figures)
Production
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLs (bbls/d)
Total (boe/d)
(1)
(2)
(3)
9,377
3,511
259
5,333
June 30, March 31,
Dec. 31,
Sept .30,
June 30, March 31,
2012
2011
2011
2011
2011
($)
($)
($)
($)
($)
18,437
9,852
0.15
0.14
14,277
5,741
0.09
0.09
11,873
4,094
0.06
0.06
9,440
3,795
0.06
0.06
9,465
4,777
0.08
0.08
1,969
(833)
(0.02)
(0.02)
12,555
1,294
0.02
0.02
292,348
33,205
(69,698)
187,308
14,696
5,603
0.08
0.08
266,649
29,699
(50,803)
185,207
4,064
(3,199)
(0.05)
(0.05)
240,124
36,715
(30,898)
178,732
754
(9,330)
(0.15)
(0.15)
213,239
20,529
(16,901)
167,568
8,910
(353)
(0.01)
(0.01)
206,885
25,009
(3,356)
176,346
2,299
(899)
(0.01)
(0.01)
195,267
12,490
17,871
174,850
(4,863)
(1,991)
(0.05)
(0.05)
192,682
129,529
20,659
175,423
8,883
2,953
259
4,692
8,687
2,091
266
3,805
8,657
1,316
283
3,042
7,714
957
161
2,403
8,167
597
177
2,135
8,214
609
189
2,167
3,744
71
18
713
The selected quarterly information was prepared in accordance with the accounting principles described in the notes to the financial statements, except for
funds from (used in) operations, which is not prescribed under IFRS.
Total capital expenditures, including acquisitions.
Current assets less current liabilities, excluding current derivative financial instruments.
Factors That Have Caused Variations over the Quarters
During the first quarter of 2011, DeeThree completed the acquisition of the Peace River and Brazeau properties that significantly
increased the Company’s revenues, funds from operations and cash flow. DeeThree’s production also increased significantly and
shifted from an approximate 98 percent natural gas focus to approximately 63 percent natural gas and 37 percent crude oil and
NGLs for the year ended December 31, 2011.
During 2012, the Company was successful with an active drilling program primarily at the Ferguson and Brazeau properties.
Capital expenditures of $144,753,000 resulted in 30 gross (28.8 net) wells drilled. This contributed to a 122 percent year-over-year
volume increase and a production split of 35 percent natural gas and 65 percent oil and NGLs for the year.
For the quarter ended December 31, 2012, the Company achieved an improved operating netback of $36.27/boe, which was
attributable to several factors. First, with a revised production split of 71 percent oil and NGLs and average production of 5,333
boe per day, the average realized price was $57.83/boe. The Company also achieved a decrease in operating costs per barrel,
both as a function of economies of scale from increased production and from operational improvements, including expanding the
oil battery and other infrastructure owned and used at Ferguson. The higher netbacks contributed to the $16,231,000 in funds
from operations recorded for the period.
Please refer to “Financial and Operating Results” and other sections for detailed discussions on variations during the comparative
quarters and to DeeThree’s previously issued interim and annual MD&A for changes in prior quarters.
46
DeeThree Exploration Ltd.
Selected Annual Information
Years Ended December 31,
(000s, except per share amounts and production figures)
(1)
Oil and natural gas revenues
Funds from operations
Per share – basic
Per share – diluted
Cash flow from operating activities
Net income (loss)
Per share – basic
Per share – diluted
Total assets
Capital expenditures
Working capital (deficit)
Shareholders’ equity
Production
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLS (bbls/d)
Total (boe/d)
(1)
(2)
2012
2011
2010
($)
($)
($)
85,112
46,088
0.69
0.68
62,292
7,181
0.11
0.11
329,666
144,753
77,586
212,090
32,747
11,833
0.21
0.21
7,100
(12,573)
(0.22)
(0.22)
213,329
187,557
(16,901)
167,568
7,073
1,689
0.07
0.07
1,729
(15,070)
(0.65)
(0.65)
65,334
22,273
28,505
55,126
8,902
2,472
267
4,223
6,974
561
137
1,860
4,258
16
1
727
Oil and gas revenues for the year ended December 31, 2010 includes gains/losses from physical fixed-price contracts.
The selected annual information was prepared in accordance with the accounting principles described in the notes to the financial statements for the years
in question
Subsequent Events
On January 18, 2013, the Company executed a purchase and sale agreement with an oil and natural gas company pursuant to
which DeeThree acquired interests in producing assets in the Peace River Arch area for consideration of approximately $2,100,000
subject to certain adjustments.
On February 19, 2013, the Company issued 4,420,000 common shares at a price of $6.80 per share for total gross proceeds of
$30,056,000 ($27,952,000 net of estimated share issuance expenses). The proceeds of the share offering will be used to conduct
development activity at Ferguson and Brazeau.
On March 12, 2013, the Company issued 663,000 common shares at $6.80 per share for total gross proceeds of $4,508,400
($4,192,800 net of estimated share issuance expenses) on the exercise in full of the underwriters’ over-allotment option from the
February issuance.
Critical Estimates
The preparation of the Company’s financial statements requires management to adopt accounting policies that involve the
use of significant estimates and assumptions. They are developed based on the best available information and are believed by
management to be reasonable under the existing circumstances. New events or additional information may result in the revision
of these estimates over time. The following discussion outlines some of the accounting policies and practices that are critical to
determining DeeThree’s financial results. A summary of the critical estimates and judgements used by DeeThree can be found in
note 2 to the audited financial statements for the year ended December 31, 2012.
2012 Annual Report
47
Reserves Determination
The proved natural gas, crude oil and NGLs reserves that are used in determining DeeThree’s depletion rates, the magnitude
of the borrowing base available to the Company from its lender and the impairment test are based on management’s best
estimates, and are subject to uncertainty. Through the use of geological, geophysical and engineering data, the reservoirs and
deposits of natural gas, crude oil and NGLs are examined to determine quantities available for future production, given existing
operations and economic conditions and technology. The evaluation of reserves is an ongoing process influenced by current
production, continuing development activities and changing economic conditions as reflected in natural gas and crude oil prices.
Consequently, the reserves are estimated, and the estimates are subject to variability. To assist with the reserves evaluation
process, the Company utilizes independent oil and natural gas reservoir engineers.
Income Taxes
The determination of DeeThree’s income and other tax liability requires interpretation of complex laws and regulations often
involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after lapse of considerable time.
Accordingly, the actual income tax liability may differ significantly from the liability estimated or recorded.
Other Estimates
The accrual method of accounting will require management to incorporate certain estimates, including revenues, royalties,
production costs and capital expenditures as at a specific reporting date but for which actual revenue and royalties have not yet
been received, and estimates on capital projects that are in progress or recently completed where actual costs have not been
received at a specific reporting date.
Controls and Procedures
Disclosure Controls
Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company is
accumulated and communicated to management (including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO)) to
allow timely decisions regarding required disclosure.
DeeThree’s CEO and CFO have concluded, based on their evaluation as of the end of the period covered by the Company’s
annual filings, that the Company’s disclosure controls and procedures are effective to provide reasonable assurance that material
information related to the issuer is made known to them by others within the Company.
Internal Controls over Financial Reporting
Management has assessed the effectiveness of the Company’s internal controls over financial reporting as defined by National
Instrument (NI) 52-109. The assessment was based on the framework in “Internal Control – Integrated Framework“ issued by the
Committee of Sponsoring Organizations. Management concluded that the Company’s internal controls over financial reporting
were effective as of December 31, 2012. No changes were made to the Company’s internal controls over financial reporting during
2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
It should be noted that while DeeThree’s CEO and CFO believe that the Company’s internal controls and procedures provide a
reasonable level of assurance and that they are effective, they do not expect that these controls will prevent all errors or fraud.
A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met.
48
DeeThree Exploration Ltd.
Accounting Standards Issued But Not Yet Applied
IFRS 9 – “Financial Instruments” replaces the guidance in IAS 39 – “Financial Instruments: Recognition and Measurement” on the
classification and measurement of financial assets. The standard eliminates the IAS 39 categories of held-to-maturity, availablefor-sale and loans and receivable. Under IFRS 9, financial assets will be classified into one of two categories on initial recognition:
financial assets measured at amortized cost; or financial assets measured at fair value. IFRS 9 is effective for annual periods
beginning on or after January 1, 2015, with early adoption permitted. The Company intends to adopt IFRS 9 in its financial
statements for the annual period beginning January 1, 2015. The Company does not expect IFRS 9 to have a material impact on
its financial statements.
IFRS 10 – “Consolidated Financial Statements” replaces the guidance in IAS 27 – “Consolidated and Separate Financial Statements”
and Standing Interpretations Committee (SIC) 12 – “Consolidation – Special Purpose Entities”. This standard provides a single
model to be applied in the control analysis for all investees, including entities that currently are special-purpose entities in the scope
of SIC 12. IFRS 10 is effective for annual periods beginning on or after January 1, 2013. The Company intends to adopt IFRS 10
in its financial statements for the annual period beginning on January 1, 2013. The Company does not expect IFRS 10 to have a
material impact on its financial statements.
IFRS 11 – “Joint Arrangements” replaces the guidance in IAS 31 – “Interests in Joint Ventures”. Under IFRS 11, joint arrangements
are classified as either joint operations or joint ventures. IFRS 11 is effective for annual periods beginning on or after January 1, 2013.
The Company intends to adopt IFRS 11 in its financial statements for the annual period beginning on January 1, 2013. The
Company does not expect IFRS 11 to have a material impact on its financial statements.
IFRS 12 – “Disclosure of Interests in Other Entities” contains disclosure requirements for entities that have interests in subsidiaries,
joint arrangements, associates and/or unconsolidated structured entities. IFRS 12 is effective for annual periods beginning on
or after January 1, 2013. The Company intends to adopt IFRS 12 in its financial statements for the annual period beginning on
January 1, 2013. The Company does not expect IFRS 12 to have a material impact on its financial statements.
IFRS 13 – “Fair Value Measurement” replaces the fair value measurement guidance contained in individual IFRS with a single
source of fair value measurement guidance. It defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date. IFRS 13 is effective for annual
periods beginning on or after January 1, 2013. The Company intends to adopt IFRS 13 in its financial statements for the annual
period beginning on January 1, 2013. The Company does not expect IFRS 13 to have a material impact on its financial statements.
In June 2011, the IASB published amendments to IAS 1 – “Presentation of Financial Statements: Presentation of Items of
Other Comprehensive Income”, which became effective for annual periods beginning on or after July 1, 2012 and are to be
applied retrospectively. Early adoption is permitted. The amendments require that an entity present separately the items of other
comprehensive income that may be reclassified to profit or loss in the future from those that would never be reclassified to
profit or loss. The Company intends to adopt the amendments in its financial statements for the annual period beginning on
January 1, 2013. As the amendments only require changes in the presentation of items in other comprehensive income, the
Company does not expect them to have a material impact on its financial statements.
2012 Annual Report
49
Business Risks and Risk Mitigation
Overall
DeeThree’s exploration and production activities are concentrated in the Western Canada Sedimentary Basin where the industry
is very competitive. There are a number of risks facing participants in the oil and natural gas industry, some of which are common
to all businesses, while others are specific to the sector. These include risks such as finding and developing oil and natural gas
reserves economically, estimating reserves, producing the reserves in commercial quantities, finding a suitable market at attractive
commodity prices, financial and liquidity risks, and environmental and safety risks.
DeeThree’s future oil and natural gas reserves and production and, therefore, its cash flows, will be highly dependent on the
Company’s success in expoiting its reserves base and acquiring additional reserves. The Company mitigates the risk of finding
and developing economical oil and natural gas reserves by utilizing a team of highly qualified professionals with expertise and
experience in these areas. DeeThree attempts to maximize drilling success by exploring areas that have multi-zone horizons,
targeting deeper horizons with uphole potential, continuously assessing new acquisition opportunities to complement existing
activities and balancing higher-risk exploratory drilling with lower-risk development drilling.
Beyond exploration risk, there is the potential that the Company’s natural gas and crude oil reserves may not be economically
produced at prevailing prices. DeeThree minimizes this risk by generating exploration prospects internally, targeting high-quality
projects, operating the project, and by attempting to access sales markets through Company-owned infrastructure or midstream operators.
Reserves Estimates
DeeThree has retained an independent engineering consulting firm that assists the Company in evaluating oil and natural gas
reserves. Reserve values are based on a number of variable factors and assumptions such as commodity prices, projected
production, future production costs and governmental regulation. The reserves and recovery information contained in the
independent reserves evaluation is an estimate. The actual production and ultimate reserves from the properties may be greater
or less than the estimates prepared by the independent reserves evaluator.
Volatility of Oil and Natural Gas Prices
The Company’s operational results and financial condition depend on the prices received for oil and natural gas production.
Natural gas prices declined in 2012 from 2011 and differentials on Canadian crude oil widened significantly in 2012 relative to
2011 due to pipeline and infrastructure constraints. There are numerous projects proposed to alleviate pipeline bottlenecks into
and in the United States, expand refinery capacity and expand or build new pipelines in Canada and the United States to source
new markets, many of which are in the regulatory application phase. There can be no assurance that such regulatory approvals
will be secured on a timely basis or at all. Oil and natural gas prices are determined by economic and, in some circumstances,
political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil
and natural gas regions, influence prices. DeeThree is exposed to commodity price risk whereby the fair value of future cash flows
will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are affected by not only
the relationship between the Canadian and United States dollars, but also global economic events that dictate the levels of supply
and demand. The Company protects itself from fluctuations in prices by maintaining an appropriate hedging strategy. As at the
date of this MD&A, DeeThree has five crude oil hedges in place (see “Commodity Prices and Foreign Exchange”). Most commodity
prices are based on U.S. dollar benchmarks, which result in the Company’s realized prices being influenced by the Canadian/U.S.
exchange rates. The Company does not sell or transact in foreign currency, but may be impacted by foreign currency exchange
rate changes related to commodity prices as outlined above. At the date of this MD&A, DeeThree had two foreign currency
exchange risk management contracts in place.
50
DeeThree Exploration Ltd.
Counterparty Risk
Credit risk is the risk of a counterparty failing to meet its obligations in accordance with the agreed upon terms. The Company
may be exposed to third-party credit risk through its contractual arrangements with its current or future joint venture partners,
marketers of its commodities and other parties. DeeThree has established credit policies and controls designed to mitigate the risk
of default or non-payment with respect to oil and natural gas sales, financial hedging transactions and joint venture participants.
The Company makes every effort to sell its commodities to major companies with excellent credit ratings.
Access to Capital
The oil and natural gas industry is a very capital-intensive industry, and in order to fully realize the Company’s strategic goals
and business plans, DeeThree will rely on equity markets as a source of new capital in addition to bank financing and internally
generated cash flow to fund its ongoing capital investments. DeeThree’s ability to raise additional capital will depend on a number
of factors such as general economic and market conditions that are beyond the Company’s control. Internally generated funds
will also fluctuate with changing commodity prices. DeeThree currently has a $90,000,000 syndicated facility with two banks. The
Company is required to comply with covenants under this facility and in the event it does not comply, access to capital could be
restricted or repayment could be required. DeeThree routinely reviews the covenants based on actual and forecast results and has
the ability to make changes to development plans to comply with the covenants under the credit facility. DeeThree anticipates it will
continue to have adequate liquidity to fund its financial liabilities through its future funds from operations and available bank credit.
DeeThree is committed to maintaining a strong balance sheet along with an adaptable capital expenditure program that can be
adjusted to capitalize on, or reflect, acquisition opportunities and, if necessary, a tightening of liquidity sources. From its founding
to the date of this MD&A, DeeThree has had no defaults or breaches on its bank debt or any of its financial liabilities.
Operational Matters
The operation of oil and natural gas wells involves a number of operating and natural hazards that may result in blowouts,
environmental damage and other unexpected or dangerous conditions resulting in damage to DeeThree and possible liability to
third parties. DeeThree has established an environmental, health and safety program and has updated its operational emergency
response plan and operational safety manual to address these operational issues. DeeThree maintains a comprehensive insurance
plan, which includes liability insurance, where available, in amounts consistent with industry standards as well as business
interruption insurance for selected facilities, to the extent that such insurance is available, to mitigate risks and protect against
significant losses where possible. DeeThree operates in accordance with all applicable environmental legislation and strives to
maintain compliance with such regulations.
In addition, DeeThree is also subject to other risks and uncertainties which are described in the Company’s Annual Information
Form dated March 28, 2013.
Outlook
DeeThree entered 2013 well-positioned as a focused producer with consolidated working interests in two large, game-changing
oil plays. The Company controls and operates both plays, so is able to change the pace of drilling and allocate capital to align with
cash flow and commodity price volatility.
We were pleased at the capital markets’ positive reaction to our equity issuance earlier in the first quarter. It raised gross proceeds
of $34.5 million and supports the Company’s planned 2013 capital program of approximately $150 million. This budget lets us
drill 31 net horizontal wells, including 20 net Upper Bakken wells and 11 gross (10.7 net) Belly River wells. Five of the year’s wells
will be exploratory.
Drilling results to date in 2013 continue to be strong. At Brazeau we have proved up the D zone with a well that tested at
1,190 boe per day, as announced in late February. We have also started to drill the first two commitment wells on our recent
34-section farm-in that will double the size of the Brazeau play. This year we aim to initiate a multi-well pad drilling model at
Brazeau that will enable each pad to develop 160 acres in four zones. Pad drilling will increase per-well capital efficiencies and
reduce spud-to-on-stream times.
2012 Annual Report
51
At Ferguson, we are continuing to delineate and extend the Upper Bakken pool while preparing to explore two undrilled prospects
identified on recently acquired Crown lands. A recent delineation well included a lateral leg over two miles in length and achieved
an IP30 of 448 boe per day. The longer lateral legs aim to delineate as much resource as possible and/or extend pool boundaries,
while lowering capital costs per unit of production and reserves added. Recent land acquisitions bring the Ferguson play to a total
of 75 net sections, giving us more running room than we had one year earlier, even as we de-risk the play.
For 2013 we are forecasting year-over-year production growth of approximately 67 percent, to an average rate of 6,800-7,000
boe per day, and an exit rate of 8,500-9,000 boe per day. The production weighting at year-end is expected to be approximately
81 percent crude oil and liquids and 19 percent natural gas. Based on anticipated average production and projected prices of
US$95.00 per barrel WTI, Cdn$3.20 per mcf natural gas and an exchange rate of US$1/Cdn$0.99, DeeThree is forecasting 2013
funds from operations of $100 million. The corporate oil price differential is forecast at 20 percent of WTI, which reflects the current
market environment. Our balance sheet is forecast to remain strong, with projected year-end net debt to fourth quarter annualized
funds from operations of approximately 0.8:1.0.
52
DeeThree Exploration Ltd.
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of DeeThree Exploration Ltd.
We have audited the accompanying financial statements of DeeThree Exploration Ltd. (the “Company”), which comprise the
statements of financial position as at December 31, 2012 and 2011, and the statements of operations and comprehensive income
(loss), changes in shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant
accounting policies and other explanatory information.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International
Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of
financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance
with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on our judgement, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also
includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by
management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit
opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as at
December 31, 2012 and 2011 and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Accountants
March 26, 2013
Calgary, Canada
2012 Annual Report
53
STATEMENTS OF FINANCIAL POSITION
As at
(000s)
Assets
Current assets
Accounts receivable
Deposits and prepaid expenses
Derivative financial instruments (note 16)
December 31,
2012
2011
($)
($)
18,823
940
850
15,906
500
–
20,613
16,406
Non-current assets
Exploration and evaluation assets (note 5)
Property and equipment (note 6)
Deferred tax asset (note 11)
29,893
279,160
–
18,631
176,562
1,640
Total assets
329,666
213,239
63,104
34,245
–
8,521
24,786
383
97,349
33,690
13,982
2,955
3,290
–
10,363
973
–
645
Total liabilities
117,576
45,671
Shareholders’ equity
Share capital (note 9)
Contributed surplus
Deficit
231,415
5,578
(24,903)
196,901
2,751
(32,084)
Total shareholders’ equity
212,090
167,568
Total liabilities and shareholders’ equity
329,666
213,239
Liabilities
Current liabilities
Bank debt (note 7)
Accounts payable and accrued liabilities
Derivative financial instruments (note 16)
Non-current liabilities
Decommissioning liabilities (note 8)
Flow-through share premium liabilities (note 9)
Deferred tax liability (note 11)
Long-term derivative financial instruments (note 16)
Commitments (note 18)
Subsequent events (note 19)
See accompanying notes to the financial statements.
On behalf of the Board of Directors,
Michael Kabanuk
Director
54
December 31,
DeeThree Exploration Ltd.
Dennis Nerland
Director
STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME (LOSS)
Years Ended December 31,
2012
2011
($)
($)
85,112
(15,670)
32,747
(6,056)
69,442
26,691
18,964
4,351
31,264
1,823
3,068
10,795
4,412
14,892
1,030
7,987
59,470
(1,879)
(1,621)
2,120
–
39,116
1,027
(206)
352
(213)
58,090
40,076
Income (loss) before income tax
Taxes
Deferred income tax expense (recovery) (note 11)
11,352
(13,385)
4,171
(812)
Net income (loss) and comprehensive income (loss) for the year
Deficit, beginning of year
7,181
(32,084)
(12,573)
(19,511)
Deficit, end of year
(24,903)
(32,084)
0.11
0.11
(0.22)
(0.22)
(000s, except per share amounts)
Revenue
Oil and natural gas revenues
Royalties
Oil and natural gas revenues, net of royalties
Expenses
Operating and transportation
General and administrative
Depletion and depreciation (note 6)
Share-based compensation (note 10)
Exploration and evaluation expense (note 5)
Unrealized loss (gain) on financial instruments
Realized gain on financial instruments
Accretion and finance expenses (notes 8, 14)
Finance income (note 14)
Net income (loss) per share (note 9)
Basic
Diluted
See accompanying notes to the financial statements.
2012 Annual Report
55
STATEMENTS OF CHANGES IN
SHAREHOLDERS’ EQUITY
Share
Capital
Contributed
Surplus
Deficit
Total
Equity
($)
($)
($)
($)
Balance – January 1, 2012
Common shares issued
Flow-through shares issued
Share issuance costs
Tax benefit of share issuance costs
Premium on flow-through shares
Share-based compensation
Exercise of options
Net income
196,901
17,267
22,258
(2,854)
713
(3,454)
–
584
–
2,751
–
–
–
–
–
2,994
(167)
–
(32,084)
–
–
–
–
–
–
–
7,181
167,568
17,267
22,258
(2,854)
713
(3,454)
2,994
417
7,181
Balance – December 31, 2012
231,415
5,578
(24,903)
212,090
Balance – January 1, 2011
Common shares issued
Flow-through shares issued
Share issuance costs
Tax benefit of share issuance costs
Premium on flow-through shares
Share-based compensation
Exercise of options
Net loss
73,530
116,602
15,450
(8,283)
2,094
(2,550)
–
58
–
1,107
–
–
–
–
–
1,654
(10)
–
(19,511)
–
–
–
–
–
–
–
(12,573)
55,126
116,602
15,450
(8,283)
2,094
(2,550)
1,654
48
(12,573)
Balance – December 31, 2011
196,901
2,751
(32,084)
167,568
(000s)
See accompanying notes to the financial statements.
56
DeeThree Exploration Ltd.
STATEMENTS OF CASH FLOWS
Years Ended December 31,
(000s)
2012
2011
($)
($)
Cash flow from (used in):
Operating activities
Net income (loss) for the period
Adjustments for:
Depletion and depreciation
Deferred income tax expense (recovery)
Share-based compensation
Accretion (note 8)
Unrealized loss (gain) on financial instruments
Exploration and evaluation expense
7,181
(12,573)
31,264
4,171
1,929
354
(1,879)
3,068
14,892
(812)
1,078
234
1,027
7,987
Change in non-cash working capital (note 12)
46,088
16,204
11,833
(4,733)
62,292
7,100
54,583
39,942
(2,854)
8,521
130,717
(8,283)
91,671
130,955
(122,651)
(14,645)
1,000
(7,457)
(10,210)
(48,038)
(13,540)
8,000
(125,979)
8,508
(153,963)
(171,049)
Change in cash and cash equivalents
Cash and cash equivalents – beginning of year
–
–
(32,994)
32,994
Cash and cash equivalents – end of year
–
–
Financing activities
Increase in bank debt
Issuance of share capital
Share issuance expenses
Investing activities
Property and equipment expenditures
Exploration and evaluation expenditures
Farm-out proceeds (note 5)
Property acquisitions (note 4)
Changes in non-cash working capital (note 12)
See accompanying notes to the financial statements.
2012 Annual Report
57
NOTES TO THE FINANCIAL STATEMENTS
As at and for the years ended December 31, 2012 and 2011
1. Reporting Entity
DeeThree Exploration Ltd. (“DeeThree” or the “Company”) is a publicly traded company incorporated under the laws of
Alberta. The Company is principally engaged in the exploration for and exploitation, development and production of oil and
natural gas, and conducts many of its activities jointly with others. These financial statements reflect only the Company’s
interests in such activities. DeeThree is registered and domiciled in Canada. Its main office is at Suite 2200, 520 Third Avenue
S.W., Calgary, Alberta.
2. Basis of Presentation
(a) Statement of Compliance
These financial statements were prepared in accordance with International Financial Reporting Standards and
interpretations (collectively referred to as IFRS) as issued by the International Accounting Standards Board (IASB).
The financial statements were authorized for issuance by the Board of Directors on March 26, 2013.
(b) Basis of Measurement
The financial statements of DeeThree were prepared on the historical cost basis, except for share-based transactions,
which are measured at fair value. The methods used to measure fair values are discussed in note 15.
(c) Functional and Presentation Currency
The financial statements are presented in Canadian dollars, the Company’s functional currency.
(d) Use of Estimates and Judgements
The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates
and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income
and expenses. Actual results may differ from these estimates and affect the results reported in these financial statements,
and could be material. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting
estimates are recognized in the year in which the estimates are revised and in any future years affected.
i) Key Sources of Estimation Uncertainty
The following are key estimates and the underlying assumptions made by management affecting the measurement of
balances and transactions in these financial statements.
Acquisitions
s
58
In a business combination, management makes estimates of the fair value of assets acquired and liabilities
assumed, which includes assessing the value of oil and natural gas properties based up the estimation of
recoverable quantities of proved plus probable reserves being acquired.
DeeThree Exploration Ltd.
Valuation of Property and Equipment
s
Estimation of recoverable quantities of proved plus probable reserves includes assumptions regarding future
commodity prices, exchange rates, discount rates and production and transportation costs for future cash flows
as well as the interpretation of complex geological and geophysical models and data. Changes in reported reserves
can affect the impairment of assets, the decommissioning obligations, the economic feasibility of exploration and
evaluation assets and the amounts reported for depletion, depreciation and amortization of property, plant and
equipment. These reserve estimates are verified by third-party professional engineers, who work with information
provided by the Company to establish reserve determinations in accordance with National Instrument (NI) 51-101,
“Standards of Disclosure for Oil and Gas Activities”.
s
Oil and natural gas development and production assets are depleted on a unit-of-production basis at a rate
calculated by reference to proved and probable reserves determined in accordance with NI 51-101 and
incorporate the estimated future cost of developing and extracting those reserves. Proved and probable reserves
are estimated using independent reserve engineers’ reports and represent the estimated quantities of oil, natural
gas and NGLs that geological, geophysical and engineering data demonstrate with a specified degree of certainly
to be recoverable in future years from known reservoirs and which are considered commercially producible.
Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable, it
being 90 percent likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves, it being
equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves. The level of estimated reserves is also a key determinant in assessing whether the
carrying value of any of the Company’s development and production assets has been impaired.
s
The recoverable amounts of cash-generating units (CGUs) and individual assets have been determined based
on the higher of the present value of value-in-use calculations and discounted fair values less costs to sell. These
calculations require the use of estimates and assumptions, including the discount rate. It is reasonably possible
that the commodity price assumptions may change, which may then impact the estimated life of the field and
economically recoverable reserves, and may then require a material adjustment to the carrying value of property
and equipment. The Company monitors internal and external indicators of impairment relating to its tangible
assets.
Provisions for Decommissioning Costs
s
The Company estimates the decommissioning obligations for oil and natural gas wells and their associated
production facilities and pipelines. In most instances, removal of assets and remediation occurs many years
into the future. Amounts recorded for the decommissioning obligations and related accretion expense require
assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required,
the engineering methodology for estimating cost, inflation estimates, future removal technologies in determining
the removal cost, and the estimate of the liability specific discount rates to determine the present value of these
cash flows.
Measurement of Share-Based Compensation
s
The Company’s estimate of stock-based compensation depends on estimates of historical volatility, dividend
yield, expected term and forfeiture rates.
Valuation and Utilization of Tax Losses
s
The deferred tax liability is based on estimates as to the timing of the reversal of temporary differences, substantively
enacted tax rates and the likelihood of assets being realized.
s
Valuation of derivative financial instruments
s
The Company’s estimate of the fair value of derivative financial instruments depends on estimated forward prices
and volatility in those prices.
2012 Annual Report
59
ii) Judgements
The following are critical judgements that management has made in the process of applying accounting policies and
that have the most significant effect on the amounts recognized in the financial statements.
Impairment
The Company’s assets are aggregated into CGUs for the purpose of calculating impairment. CGUs are based on an
assessment of the unit’s ability to generate independent cash inflows. The determination of the Company’s CGUs was
based on management’s judgement in regards to shared infrastructure, geographical proximity, petroleum type and
similar exposure to market risk and materiality.
Judgments are required to assess when impairment indicators are evident and impairment testing is required. In
determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based
on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value
of land and other relevant assumptions.
Exploration and Evaluation Assets
The application of the Company’s accounting policy for exploration and evaluation assets requires management to
make certain judgments as to future events and circumstances as to whether economic quantities of reserves have
been found.
Income Taxes
Judgments are made by management to determine the likelihood whether deferred income tax assets at the end of
the reporting period will be realized from future taxable earnings.
Contingencies
By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The
assessment of contingencies inherently involves the exercise of significant judgement and estimates of the outcome
of future events.
3. Significant Accounting Policies
The accounting policies set out below were applied consistently to all periods presented in these financial statements. Certain
comparative amounts were reclassified to conform with the current period’s presentation as noted below.
(a) Property and Equipment
Capitalization
Items of property and equipment, which include oil and natural gas development and production assets, are measured at
cost less accumulated depletion, depreciation and impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing
the asset into operation, the initial estimate of decommissioning obligation, if any, and, for qualifying assets, borrowing
costs. Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs
of replacing parts of property and equipment are recognized as petroleum and natural gas properties only when they
increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are
recognized in profit or loss as incurred. Such capitalized petroleum and natural gas properties generally represent costs
incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and
are accumulated on a field or geotechnical area basis.
60
DeeThree Exploration Ltd.
Depletion and Depreciation
The net carrying value of development and production assets is depleted using the unit-of-production method by reference
to the ratio of production in the year to the related proved plus probable reserves, taking into account estimated future
development costs necessary to convert those reserves into production. Proved plus probable reserves are estimated
annually by independent qualified reserves evaluators and represent the estimated quantities of crude oil, natural gas
and NGLs which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be
recoverable in future years from known reservoirs and which are considered commercially producible. Future development
costs are estimated taking into account the amount of physical development that will be required to produce the reserves.
For interim financial statements, internal estimates of changes in reserves and future development costs are used for
determining depletion for the period.
For depletion purposes, relative volumes of petroleum and natural gas production and reserves are converted at the
energy-equivalent conversion rate of 6,000 cubic feet of natural gas to 1 barrel of crude oil.
Other property and equipment are stated in the statement of financial position at cost less accumulated depreciation.
Depreciation is calculated over the estimated useful life of the asset based on the original cost less estimated residual
value. The methods and useful lives of the Company’s other property and equipment are as follows:
s
Facilities
20 years straight-line
s
Office equipment
5 years declining balance
s
Computer equipment
3 years declining balance
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
Impairment
At each reporting date, DeeThree assesses its development and production assets for possible impairment if there
are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable. Such
indicators include changes in the business plans, significant downward revisions of estimated volumes, significant
declines in commodity prices, increases in estimated future development expenditures, changes in regulations, evidence
of physical damage and low plant utilization. If any such indicator is evident, the asset’s recoverable amount is estimated.
The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount, that is, the
higher of fair value less costs to sell and value in use. Each CGU is identified in accordance with International Accounting
Standard (IAS) 36 – “Impairment of Assets”. If necessary, impairment is charged through the statement of income and
comprehensive income if the capitalized costs of the CGU exceed the recoverable amount.
Impairment losses recognized in prior periods are assessed at each reporting date for any indications that the loss has
decreased or been erased. An impairment loss is reversed if there has been an increase in the estimated recoverable
amount of a previously impaired asset. An impairment loss may never be reversed beyond the asset’s original carrying
amount, net of depreciation or depletion.
(b) Exploration and Evaluation (E&E) Assets
Capitalization
Pre-licence costs are recognized in the statement of operations as incurred.
Oil and natural gas E&E assets are accounted for in accordance with IFRS 6 – “Exploration for and Evaluation of
Mineral Resources” whereby costs associated with the exploration for and evaluation of oil and natural gas reserves are
accumulated on an area-by-area basis and are capitalized as either tangible or intangible E&E assets when incurred.
Pre-licence costs are recognized in the statement of income and comprehensive income as incurred. E&E costs, including
the costs of acquiring licences and of drilling and completing wells, initially are capitalized as E&E assets according to the
expenditure’s nature. The costs are accumulated in cost centres by well, field or exploration area pending determination
of technical feasibility and commercial viability.
2012 Annual Report
61
When a specific well, field or area is determined to be technically feasible and commercially viable, the accumulated costs
are transferred to property and equipment. When a specific well, field or area is determined not to be technically feasible
or commercially viable, or the Company decides not to continue with the project, the unrecoverable costs are charged to
profit or loss as E&E expenses.
No depletion or depreciation is provided for E&E assets.
Impairment
E&E assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial
viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes
of impairment testing, E&E assets are tested at an operating segment level.
(c) Business Combinations
The purchase method of accounting is used to account for corporate acquisitions and assets that meet the definition of
a business combination under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity
instruments issued and liabilities incurred or assumed at the date of closing. Identifiable assets acquired and liabilities
and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition
date. The excess of the cost of acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities
acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the
difference is recognized immediately in the statement of income and comprehensive income.
(d) Leased Assets
Other leases are operating leases, which are not recognized on the Company’s statement of financial position. Payments
made under operating leases are recognized in profit or loss on a straight-line basis over the lease’s term. Lease incentives
received are recognized as an integral part of the total lease expense over the lease’s term.
(e) Joint Interest Activities
A portion of the Company’s exploration, development and production activities are conducted jointly with other entities
and, accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.
(f) Revenue Recognition
Oil, natural gas and NGLs sales are recognized when commodities are sold and title passes to the customer. Royalty
expense is recognized as it accrues in accordance with the terms of the overriding royalty agreements.
(g) Decommissioning Liabilities
The present value of expected future abandonment and reclamation costs is recorded on the statement of financial position
as both a decommissioning liability and a charge to property and equipment at the time the obligation is incurred. The
amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions
and is discounted using a risk-free interest rate. The amount included as property and equipment is depleted over the life
of the reserves by the unit-of-production method. The liability accretes until the Company settles the decommissioning
liability; this accretion charge is included as a finance cost on the statement of income and comprehensive income. Actual
reclamation and abandonment costs incurred are charged against the liability to the extent the liability was established.
Estimates for future abandonment and reclamation costs are based on historical costs to abandon and reclaim similar
sites, taking into consideration current costs. The liability is based on the Company’s net interest in the respective sites.
62
DeeThree Exploration Ltd.
(h) Income Taxes
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss, except to the
extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively
enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition
of assets or liabilities in a transaction that is not a business combination.
Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they are
reversed, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets
and liabilities are offset if there is a legally enforceable right to do so, and they relate to income taxes levied by the same
tax authority on the same taxable entity, or on different taxable entities, but they intend to settle current tax liabilities and
assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which
the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the
extent that it is no longer probable that the related tax benefit will be realized.
(i) Flow-Through Shares
The Company finances a portion of its exploration and development activities through the issuance of flow-through
shares. Under flow-through share agreements, the resource expenditure deductions for income tax purposes related to
exploratory development activities are renounced to subscribers in accordance with tax legislation. Flow-through shares
issued are recorded in share capital at the fair value of common shares on the date of issuance. The premium received on
issuing flow-through shares is initially recorded as a long-term premium liability. As qualifying expenditures are incurred,
the premium is reversed and a deferred income tax liability is recorded. The net amount is then recognized as deferred
income tax expense.
(j) Cash and Cash Equivalents
Cash and cash equivalents comprise cash on hand, term deposits held with banks and other short-term highly liquid
investments with maturities of three months or less at the time of purchase.
(k) Share-Based Compensation
The fair value of the options is determined using the Black-Scholes option pricing model and each tranche in an award
is considered a separate award with its own vesting period and grant date fair value. The grant date fair value of options
granted to officers, directors, employees and certain consultants is recognized as compensation expense with a
corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and
is adjusted to reflect the actual number of options that vest.
Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed
surplus is recorded as an increase in share capital. In the event that vested options expire, previously recognized
compensation expense associated with such stock options is not reversed. In the event that options are forfeited,
previously recognized compensation expense associated with the unvested portion of such stock options is reversed.
(l) Financial Instruments
i) Non-Derivative Financial Instruments
Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, bank debt, and
accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value plus,
for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial
recognition, non-derivative financial instruments are measured as described below.
2012 Annual Report
63
Cash and Cash Equivalents
Cash and cash equivalents comprise cash on hand, term deposits held with banks and other short-term highly liquid
investments with maturities of three months or less. Bank overdrafts that are repayable on demand and form an
integral part of the Company’s cash management, whereby Company management has the ability and intent to net
bank overdrafts against cash, are included as a component of cash and cash equivalents for the purpose of the
statement of cash flows.
Financial Assets at Fair Value through Profit or Loss
An instrument is classified as fair value through profit or loss if it is held for trading or is designated as such upon initial
recognition. Financial instruments are designated as fair value through profit or loss if the Company manages such
investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk
management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or
loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes
therein are recognized in profit or loss. The Company has designated cash and cash equivalents at fair value.
Other
Other non-derivative financial instruments, which may include accounts receivable, accounts payable and accrued
liabilities, and bank debt, are measured at amortized cost using the effective interest rate method less any impairment
losses.
ii) Derivative Financial Instruments
The Company may enter into certain financial derivative contracts in order to manage the exposure to market risks
from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The
Company has not designated its financial derivative contracts as effective accounting hedges and, therefore, has not
applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges.
As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the
statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred. As at
December 31, 2011, the Company has commodity and foreign exchange financial derivative contracts.
Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics
and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the
same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is
not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are
recognized immediately in profit or loss. The Company does not have any embedded derivatives that are separately
accounted for.
(m) Share Capital
Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares and
stock options are recognized as a deduction from equity, net of deferred income taxes.
(n) Per Share Amounts
Basic net income or loss per share is calculated by dividing the profit or loss attributable to common shareholders of the
Company by the weighted-average number of common shares outstanding during the period. Diluted per share amounts
are determined by adjusting the profit or loss attributable to common shareholders and the weighted-average number of
common shares outstanding for the effects of dilutive instruments, such as stock options and warrants granted using the
treasury stock method. Should the Company have a loss for the period, options and warrants would be anti-dilutive and,
therefore, will have no effect on the determination of loss per share.
64
DeeThree Exploration Ltd.
4. Acquisitions
During the fourth quarter of 2012, the Company acquired oil and natural gas assets principally located in the Brazeau area
of west-central Alberta for total cash consideration of $7,457,000. The property acquisition closed on October 4, 2012
and was accounted for as a business combination under IFRS 3 – “Business Combinations”. Acquisition costs of $42,000
were charged to general and administrative expense on the statement of income and comprehensive income. Had the
acquisition closed January 1, 2012, the Company estimates that its pro forma revenue and net income for the year ended
December 31, 2012 would have been approximately $86,738,000 and $8,227,000, respectively.
(000s)
($)
Net assets acquired
Petroleum and natural gas assets
E&E assets
Decommissioning liabilities
8,458
91
(1,092)
7,457
Consideration
Total cash consideration
7,457
During the first quarter of 2011, the Company acquired oil and natural gas assets principally located in the Peace River Arch
area of northwest Alberta and the Brazeau area of west-central Alberta for total cash consideration of $123,185,000. The
property acquisition closed on March 22, 2011 and was accounted for as a business combination under IFRS 3. Acquisition
costs of $1,125,000 were charged to general and administrative expense on the statement of income and comprehensive
income. Had the acquisition closed January 1, 2011, the Company estimates that its pro forma revenue and net loss for the
year ended December 31, 2011 would have been approximately $39,200,000 and $13,064,000, respectively.
(000s)
($)
Net assets acquired
Petroleum and natural gas assets
E&E assets
Adjustments related to January 1 to March 22, 2011 period
Decommissioning liabilities
122,081
7,773
(1,815)
(4,854)
123,185
Consideration
Total cash consideration
123,185
5. Exploration and Evaluation Assets
Years Ended December 31,
(000s)
Balance – beginning of period
Additions
Farm-out proceeds
Acquisitions through business combinations
Transfers to property and equipment
E&E expenses
Lease expiries
Balance – end of period
2012
2011
($)
($)
18,631
115,111
(1,000)
91
(99,872)
(232)
(2,836)
11,052
57,010
(8,000)
8,249
(41,693)
(7,474)
(513)
29,893
18,631
2012 Annual Report
65
E&E assets consist of the Company’s exploration projects that are pending the determination of proved or probable reserves.
Additions represent the Company’s share of costs incurred on E&E assets during the period and acquisitions represent E&E
assets included in business combinations during the period.
During the year ended December 31, 2012, the Company did not incur costs to drill unsuccessful wells and, as such, no
dry and abandoned amounts were expensed during the year (2011 – $6,761,000). As part of the year-end review of the
value of E&E assets, the Company determined that preliminary drilling costs of $232,000 in the year ended December
31, 2012 (2011 – $713,000) should be expensed as the Company no longer plans to drill those locations. In addition,
an expense of $2,836,000 for the year ended December 31, 2012 (2011 – $513,000) was recorded to recognize lease
expiries on undeveloped land during the year. During the year ended December 31, 2012, approximately $1,123,000 of
directly attributable general and administrative expense and $693,000 of directly attributable share-based compensation were
capitalized as E&E expenditures (2011 – $681,000 and $394,000, respectively).
6. Property and Equipment
Oil and
Natural Gas
Properties
Office
Equipment
Total
($)
($)
($)
Cost or deemed cost
Balance – January 1, 2011
Acquisitions through business combinations
Additions
Transfers from E&E assets
37,692
122,883
8,926
41,693
59
–
194
–
37,751
122,883
9,120
41,693
Balance – December 31, 2011
Acquisitions through business combinations
Additions
Transfers from E&E assets
211,194
8,458
25,476
99,872
253
–
56
–
211,447
8,458
25,532
99,872
Balance – December 31, 2012
345,000
309
345,309
Accumulated depletion and depreciation
Balance – January 1, 2011
Depletion and depreciation for the year
19,970
14,871
23
21
19,993
14,892
Balance – December 31, 2011
Depletion and depreciation for the period
34,841
31,212
44
52
34,885
31,264
Balance – December 31, 2012
66,053
96
66,149
176,353
278,947
209
213
176,562
279,160
(000s)
Net book value
December 31, 2011
December 31, 2012
(a) Capitalization of General and Administrative and Share-Based Compensation Expenses
During the year ended December 31, 2012, approximately $516,000 of directly attributable general and administrative
expense and $372,000 of directly attributable share-based compensation expense were capitalized as expenditures on
property and equipment (2011 – $203,000 and $182,000, respectively).
(b) Amortization and Impairment Charges
At December 31, 2012, as a result of decreasing natural gas prices, the Company performed an impairment test on one
of its CGUs primarily based on the net present value of cash flows from oil and natural gas reserves at an appropriate
discount rate. Consideration was also given to acquisition metrics of recent transactions on similar assets. For the year
ended December 31, 2012, there were no impairment issues and, as such, no impairment was recorded.
66
DeeThree Exploration Ltd.
Impairment tests were carried out at December 31, 2012 and were based on fair value less costs to sell calculations using
the following commodity price estimates:
2013
2014
2015
2016
2017
Annual escalation thereafter
WTI
Oil
Foreign
Exchange
Rate
Edmonton
Reference
Price
AECO
Gas
(US$/bbl)
(US$/Cdn$)
(Cdn$/bbl)
(Cdn$/mmbtu)
89.63
89.93
88.29
95.52
96.96
1.5%
1.001
1.001
1.001
1.001
1.001
1.5%
84.55
89.84
88.21
95.43
96.87
1.5%
3.31
3.72
3.91
4.70
5.32
1.5%
(c) Future Development Costs and Salvage Value
During 2012, an estimated $158,947,000 of future development costs associated with proved plus probable undeveloped
reserves were included in the calculation of depletion and depreciation expense and an estimated $13,157,000 of salvage
value of production equipment was excluded (2011 – $44,747,000 and $2,791,000, respectively).
7. Bank Debt
At December 31, 2012, the Company had a revolving demand credit facility with an authorized borrowing base of $90,000,000
with interest charged at a rate per annum equal to the Canadian prime rate during said period plus the applicable margin,
being a range of 0.50 percent to 2.50 percent, as determined by the Corporation’s debt to cash flow ratio. Standby fees
associated with this facility are charged based on an applicable margin, being a range of 0.2 percent to 0.45 percent per
annum on the undrawn portion of the facility, again based on the Company’s debt to cash flow ratio. Under this credit facility,
the Corporation is required to maintain a current ratio of not less than 1:1.
At December 31, 2012, $63,104,000 (December 31, 2011 – $8,521,000) was drawn against the revolving demand credit
facility. The amount of the facility is subject to a borrowing base test performed on a periodic basis by the lenders, based
primarily on reserves and using commodity prices estimated by the lenders as well as other factors. The borrowing base of
the credit facility is subject to review at least semi-annually with the next review to take place not later than May 30, 2013. A
decrease in the borrowing base could result in a reduction to the credit facility. Collateral for this facility consists of a general
security agreement, providing a security interest over all present and subsequently acquired personal property and a floating
charge on all present and subsequently acquired land interests of the Company.
2012 Annual Report
67
8. Decommissioning Liabilities
The Company has estimated the net present value of decommissioning obligations to be $13,982,000 as at December 31, 2012
(December 31, 2011 – $10,363,000) based on an undiscounted total future liability of $17,642,000 (December 31, 2011 –
$14,398,000). These payments are expected to be incurred over a period of one to 20 years with the majority of costs to
be incurred between 2013 and 2026. At December 31, 2012, a risk-free rate of 2.25 percent (December 31, 2011 – 3.5
percent) and an inflation rate of 2 percent (December 31, 2011 – 2 percent) were used to calculate the net present value of
the decommissioning liabilities.
Years Ended December 31,
2012
2011
($)
($)
Balance – beginning of period
Liabilities incurred
Liabilities acquired
Revisions
Settlements
Accretion of decommissioning liabilities
10,363
1,044
1,092
1,237
(108)
354
2,498
538
5,154
2,055
(116)
234
Balance – end of period
13,982
10,363
(000s)
9. Share Capital
(a) Authorized
Unlimited number of common voting shares, no par value.
Unlimited number of preferred shares, no par value, issuable in series.
(b) Issued – Common Shares
Years ended December 31,
2012
2011
Shares
Amount
Shares
Amount
(#)
($000s)
(#)
($000s)
Balance – beginning of period
Common shares issued (i)
Flow-through shares issued (ii)
Premium on flow-through shares (ii)
Exercise of options (iii)
Share issuance costs
Tax benefit of share issuance costs
63,152,091
3,139,500
4,604,100
–
184,482
–
–
196,901
17,267
22,258
(3,454)
584
(2,854)
713
32,937,091
27,195,000
3,000,000
–
20,000
–
–
73,530
116,602
15,450
(2,550)
58
(8,283)
2,094
Balance – end of period
71,080,173
231,415
63,152,091
196,901
i) Common Share Issuances
In October 2012, DeeThree issued 3,139,500 common shares at a price of $5.50 per common share, for total
gross proceeds of $17,267,250 ($16,008,500 net of share issuance expenses), including 409,500 common shares
($2,252,250) issued on exercise in full of the underwriters’ over-allotment option.
In July 2011, DeeThree issued 400,000 common shares at a price of $3.46 per common share in exchange for
approximately 12,800 net acres of undeveloped land located primarily in the Peace River Arch area of Alberta. Share
issuance expenses of approximately $7,000 were recorded in relation to this transaction and the value of the acquired
land was included in the Company’s E&E balance at December 31, 2011.
In March 2011, DeeThree issued 26,795,000 common shares at a price of $4.30 per common share for total gross
proceeds of $115,219,000 ($107,934,000 net of share issuance expenses), including 3,495,000 common shares
($15,029,000) issued on the exercise in full of the underwriters’ over-allotment option.
68
DeeThree Exploration Ltd.
ii) Flow-Through Share Issuances
In October 2012, DeeThree issued 770,000 flow-through shares at a price of $6.50 per flow-through share for total
gross proceeds of $5,005,000 ($4,650,000 net of share issuance expenses). The implied premium on the flow-through
shares of $1.00 per share or $770,000 was initially recorded as a liability on the statement of financial position, and
$770,000 remains at December 31, 2012. To date, the Company has incurred $nil of the total $5,005,000 of qualified
exploration and development expenditures, with the full amount to be spent by December 31, 2013.
In March 2012, DeeThree issued 3,834,100 flow-through shares at a price of $4.50 per flow-through share for total
gross proceeds of $17,253,450 ($16,012,450 net of estimated share issuance expenses), including 500,100 flowthrough shares ($2,250,450) issued on the exercise in full of the underwriters’ over-allotment option. The implied
premium on the flow-through shares of $0.70 per share or $2,683,870 was initially recorded as a liability on the
statement of financial position and $2,185,000 remains at December 31, 2012. To date, the Company has incurred
$3,206,000 of the total $17,253,450 of qualified exploration and development expenditures and the remainder will be
spent by December 31, 2013.
In March 2011, DeeThree issued 3,000,000 flow-through shares at a price of $5.15 per flow-through share for total
gross proceeds of $15,450,000 ($14,460,000 net of share issuance expenses) and $0.85 per share or $2,550,000
was determined to be the implied premium on the flow-through shares. At December 31, 2012, $nil of the flow-through
share premium remains on the statement of financial position as a liability as the Company fulfilled this commitment for
qualified exploration and development expenditures during the second quarter of 2012.
iii) Exercising of Options
In November 2012, 53,000 options were exercised at a weighted-average price of $1.80 per share for total cash
proceeds of $95,000 and previously recognized share-based compensation expense of $54,000.
In October 2012, 81,482 options were exercised at a weighted-average price of $3.18 per share for total cash
proceeds of $262,000 and previously recognized share-based compensation expense of $65,000.
On September 13, 2012, 50,000 options were exercised at a weighted-average price of $1.20 per share for total cash
proceeds of $60,000 and previously recognized share-based compensation expense of $48,000.
On January 6, 2011, 10,000 options were exercised at a weighted-average price of $2.45 per share and on
March 16, 2011, 10,000 options were exercised at a weighted-average price of $2.29 per share for total cash proceeds
of $48,000 and previously recognized share-based compensation expense of $10,000.
(c) Per Share Amounts
Per share amounts were calculated on the weighted-average number of shares outstanding. The basic and diluted shares
outstanding were as follows:
Years Ended December 31,
(000s, except per share amounts)
Net income (loss) for the period
Weighted average number of common shares
– basic
– diluted
Net income (loss) per weighted average common share
– basic
– diluted
2012
2011
($)
($)
7,181
(12,573)
(#)
(#)
66,902
68,130
56,407
56,407
($)
($)
0.11
0.11
(0.22)
(0.22)
2012 Annual Report
69
10. Share-Based Compensation
The Company has an option program that entitles officers, directors, employees and certain consultants to purchase Company
shares. Options are granted based on the five-day volume-weighted average common share price prior to the date of grant,
vest 20 percent after six months and then 20 percent on the first, second, third and fourth anniversaries from the grant date
and expire five years from the grant date.
The number and weighted-average exercise prices of stock options are as follows:
Years Ended December 31,
2012
2011
Options
WeightedAverage
Exercise
Price
Options
WeightedAverage
Exercise
Price
(#)
($)
(#)
($)
Outstanding – January 1
Issued
Exercised
Forfeited
4,382,200
1,565,058
(184,482)
(63,144)
2.89
3.93
2.25
3.23
1,885,000
2,603,000
(20,000)
(85,800)
2.26
3.35
2.37
3.00
Outstanding – end of period
5,699,632
3.19
4,382,200
2.89
Exercisable – end of period
2,427,430
2.86
1,177,900
2.57
The fair value of the common share purchase options granted was estimated as at the date of grant using the Black-Scholes
option pricing model and the following weighted-average assumptions:
Weighted-Average
Exercise Price
($)
As at December 31, 2012
1.20 – 1.99
2.00 – 2.99
3.00 – 3.99
4.00 – 4.99
5.00 – 5.99
6.00 – 6.07
Options
Outstanding
WeightedAverage
Contractual
Life
Options
Exercisable
(#)
(years)
(#)
125,000
2,887,000
1,024,074
1,598,558
15,000
50,000
0.42
2.91
4.09
3.57
4.95
4.78
125,000
1,542,500
200,519
559,411
–
–
5,699,632
3.28
2,427,430
The fair value of the common share purchase options granted during the year was estimated as at the date of grant using the
Black-Scholes option pricing model and the following weighted-average assumptions:
As at December 31,
2012
2011
Risk-free interest rate (%)
Expected life (years)
Expected volatility (%)
Expected dividend yield (%)
Fair value of options granted during the year ($/share)
1.22
3.10
77
0
1.97
1.48
2.10
77
0
1.39
A forfeiture rate of 1 percent for options granted during 2012 (2011 – 0 percent) was used when recording share-based
compensation expense. This estimate is adjusted to the actual forfeiture rate. Gross share-based compensation was
$2,994,000 for the year ended December 31, 2012 (2011 – $1,654,000). Of this amount, $106,000 was reclassified to
operating expenses for the amount related to field employees (2011 – $48,000) and $1,065,000 was capitalized (2011 –
$576,000), resulting in total net share-based compensation expense of $1,823,000 for the year (2011 – $1,030,000).
70
DeeThree Exploration Ltd.
11. Income Taxes
The actual income tax provision differs from the expected amount calculated by applying the Canadian combined federal and
provincial corporate tax rates to income (loss) before income taxes. These differences are explained as follows:
Years Ended December 31,
(000s)
Income (loss) before income tax
Tax rate
Computed income tax expense (recovery) provision
Increase (decrease) in income taxes resulting from:
Rate adjustment
Share-based compensation
Flow-through shares
Other
Non-deductible expenses
Subtotal
Flow-through share premium
Income tax expense (recovery)
2012
2011
($)
($)
11,352
25%
(13,385)
26.5%
2,838
(3,547)
19
522
2,270
(13)
7
147
301
5,698
223
7
5,643
(1,472)
2,829
(3,641)
4,171
(812)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s
net deferred income tax assets and liabilities are as follows:
Years Ended December 31,
(000s)
Deferred income tax asset
Non-capital losses carried forward
Share issuance costs
Derivative financial instruments
Decommissioning liabilities
Net book value of property and equipment in excess of tax basis
Deferred income tax asset (liability)
2012
2011
($)
($)
6,132
3,063
(212)
3,496
(15,769)
1,720
3,062
259
2,623
(6,024)
(3,290)
1,640
2012 Annual Report
71
The Company has recognized a net deferred tax asset based on the independently evaluated reserves report as cash flows
are expected to be sufficient to realize the deferred income tax asset. The statutory tax rate is 25 percent as a result of tax
legislation enacted in 2007.
(000s)
E&E, and property and equipment
Derivative financial instruments
Site restoration
Share issuance costs
Non-capital loss
(000s)
E&E, and property and equipment
Derivative financial instruments
Site restoration
Share issuance costs
Non-capital loss
Balance,
January 1,
2012
Recognized
Directly in
Equity
Balance,
Recognized in December 31,
Profit or Loss
2012
($)
($)
($)
($)
(6,024)
259
2,623
3,062
1,720
–
–
–
713
–
(9,745)
(471)
873
(712)
4,412
(15,769)
(212)
3,496
3,063
6,132
1,640
713
(5,643)
(3,290)
Balance,
January 1,
2011
Recognized
Directly in
Equity
($)
($)
($)
($)
(518)
–
619
1,042
1,232
–
–
–
2,094
–
(5,506)
259
2,004
(74)
488
(6,024)
259
2,623
3,062
1,720
2,375
2,094
(2,829)
1,640
2012
2011
($)
($)
(2,917)
(440)
9,459
(108)
(15,022)
(229)
19,142
(116)
5,994
3,775
16,204
–
(10,210)
(4,733)
–
8,508
5,994
3,775
Balance,
Recognized in December 31,
Profit or Loss
2011
The Company has $24,500,000 of non-capital losses that begin to expire in 2029.
12. Supplemented Cash Flow Information
Changes in non-cash working capital are comprised of:
Years Ended December 31,
(000s)
Accounts receivable
Prepaid expenses and other
Accounts payable and accrued liabilities
Abandonment and reclamation costs
Related to operating activities
Related to financing activities
Related to investing activities
72
DeeThree Exploration Ltd.
13. Supplemental Disclosure
The aggregate payroll expense of employees and executive management was as follows:
Years Ended December 31,
2012
2011
($)
($)
Salaries and wages (including bonuses)
Benefits and other personnel costs
Share-based compensation (gross)
4,638
121
2,995
2,241
83
1,371
Total employee remuneration
Capitalized portion of total remuneration
7,754
(2,705)
3,695
(1,388)
5,049
2,307
(000s)
Personnel expenses directly attributable to capital activities have been capitalized and included in property and equipment
and E&E assets.
In addition to their salaries, the Company also provides non-cash benefits to executive officers. The executive officers include
the Executive Chairman, Chief Executive Office (CEO), Chief Financial Officer (CFO), Vice Presidents and the Controller.
Executive officers also participate in the Company’s stock option program. Compensation of key management personnel is
comprised of the following:
Years Ended December 31,
(000s)
Salaries and wages (including bonuses)
Benefits and other personnel costs
Share-based compensation (i)
(i)
(ii)
2012
2011 (ii)
($)
($)
1,664
35
1,101
679
30
770
2,800
1,479
Represents the amortization of share-based compensation associated with options granted to executive officers as recorded in the financial statements.
For the year ended December 31, 2011, the executive officers included the Executive Chairman, Chief Executive Officer (CEO), Chief Financial Officer (CFO)
and the Vice Presidents.
14. Finance Income and Expenses
Years Ended December 31,
2012
2011
(000s)
($)
($)
Finance income:
Interest income on bank deposits
–
–
(213)
–
(213)
1,328
428
10
354
27
65
26
234
2,120
352
2,120
139
Finance expenses:
Interest on bank debt
Standby and other fees related to credit facility
Part XII.6 tax related to flow-through shares
Accretion expense
Net finance expenses recognized in profit or loss
2012 Annual Report
73
15. Determination of Fair Values
A number of the Company’s accounting policies and disclosures require the determination of fair value for financial and nonfinancial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the
following methods. When applicable, further information about the assumptions made in determining fair values is disclosed
in the notes specific to that asset or liability.
(a) Property and Equipment and E&E Assets
The fair value of property and equipment recognized in a business combination is based on market values. The market
value of property and equipment is the estimated amount for which property and equipment could be exchanged on the
acquisition date between a willing buyer and a willing seller in an arm’s-length transaction after proper marketing wherein
the parties had each acted knowledgeably, prudently and without compulsion. The market value of petroleum and natural
gas properties (included in property and equipment) is estimated with reference to the discounted cash flows expected to
be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount
rate is specific to the asset with reference to general market conditions.
The market value of other items of property and equipment is based on the quoted market prices for similar items.
(b) Cash and Cash Equivalents, Accounts Receivable, Accounts Payable and Accrued Liabilities
The fair value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities is estimated
as the present value of future cash flows, discounted at the market rate of interest at the reporting date. The fair value of
these balances approximated their carrying value at December 31, 2012 due to their short term to maturity.
(c) Stock Options
The fair value of stock options is measured using the Black-Scholes option-pricing model. Measurement inputs include
share price on measurement date, exercise price of the instrument, expected volatility (based on weighted-average
historical volatility adjusted for changes expected due to publicly available information), weighted-average expected life of
the instruments (based on historical experience and general option-holder behaviour) and the risk-free interest rate (based
on Government of Canada bonds).
DeeThree classifies the fair value of these transactions according to the following hierarchy based on the nature of the
observable inputs used to value the instrument.
s
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active
markets are those in which transactions occur in sufficient frequency and volume to provide continuous pricing
information.
s
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly
or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward
prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the
marketplace.
s
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable
market data.
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities included in
the statement of financial position approximate fair value due to the short-term nature of those instruments. The fair value
measurement of the derivative financial instruments has a fair value hierarchy of Level 2.
16. Financial Risk Management
The Company has exposure to credit, liquidity and market risk. The Company’s risk management policies are established to
identify and analyze the risks it faces, to set appropriate limits and controls, and to monitor risks and adherence to market
conditions and the Company’s activities.
74
DeeThree Exploration Ltd.
(a) Credit Risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet
its contractual obligations, and arises principally from the Company’s receivables from joint venture partners and oil and
natural gas marketers. This amount was $18,823,000 at December 31, 2012 (December 31, 2011 – $15,906,000).
The Company’s accounts receivable are with customers and joint venture partners in the oil and natural gas business and
are subject to normal credit risks. Concentration of credit risk is mitigated by marketing substantially all of the Company’s
production to large purchasers under normal industry sale and payment terms. The industry has a pre-arranged monthly
settlement day for payment of revenues from all buyers of natural gas and crude oil. This occurs on the 25th day following
the month in which the production is sold. DeeThree mitigates associated credit risk by limiting transactions to creditworthy counterparties. The exposure to credit risk at the reporting date by type was:
As at December 31,
2012
2011
($)
($)
Oil and natural gas marketing companies
Joint venture partners
Other
11,670
4,930
2,223
4,676
6,253
4,977
Total trade and other receivables
18,823
15,906
(000s)
As at December 31, 2012 and 2011, the Company’s trade and other receivables are aged as follows:
Years Ended December 31,
2012
2011
($)
($)
Current (less than 90 days)
Past due (more than 90 days)
15,200
3,623
12,194
3,712
Total
18,823
15,906
(000s)
(b) Liquidity Risk
Liquidity risk is the risk of having difficulty meeting obligations associated with financial liabilities. The financial liabilities
on the statement of financial position consist of accounts payable and accrued liabilities and bank debt. This amount
consists of invoices payable to trade suppliers relating to office and field operating activities, and the Company’s capital
spending program. DeeThree processes invoices within a normal payment period. As described in note 7, the Company
increased its revolving demand credit facility to an authorized $90,000,000 borrowing base as at December 31, 2012.
DeeThree anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future funds from
operations and available bank debt. The Company had no defaults or breaches on its bank debt or any of its financial
liabilities as at or for the year ended December 31, 2012.
The following table details the Company’s financial liabilities as at December 31, 2012:
Total
Within
1 Year
Over
1 Year
($)
($)
($)
Non-derivative financial liabilities:
Bank debt
Accounts payable and accrued liabilities
63,104
34,245
63,104
34,245
–
–
Total financial liabilities
97,349
97,349
–
As at December 31, 2012
(000s)
2012 Annual Report
75
(c) Market Risk
Market risk is the risk of changes in market prices, such as commodity prices, foreign currency exchange rates and
interest rates, affecting the Company’s net earnings or value of its financial instruments. The objective of managing market
risk is to control market risk exposure within acceptable limits, while optimizing returns. The Company will enter into such
transactions in accordance with the risk management policy approved by the Board of Directors.
Commodity Price Risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity
prices. Commodity prices for crude oil and natural gas are influenced not only by the relationship between the Canadian
and United States dollars, as outlined below, but also by global economic events that dictate the levels of supply and
demand. The Company has attempted to mitigate commodity price risk through the use of financial contracts for its crude
oil production.
As at December 31, 2012, the Company had the following crude oil and foreign exchange risk management contracts,
with a total mark-to-market asset value of $850,000:
Period
Commodity
Type of Contract
Quantity
Pricing Point
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI – NYMEX
US$85.00/bbl (floor) –
US$111.00/bbl (cap) (1)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI – NYMEX
US$90.00/bbl (floor) –
US$113.25/bbl (cap) (2)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI – NYMEX
US$90.00/bbl (floor) –
US$116.25/bbl (cap) (3)
Jan. 1/13 – Dec. 31/13
Crude oil
Collar
250 bbls/d
WTI – NYMEX
US$95.00/bbl (floor) –
US$118.00/bbl (cap) (4)
Jan. 1/13 – Dec. 31/13
Crude Oil
Swap
500 bbls/d
WTI – NYMEX
US$90.00/bbl (floor) –
US$106.00/bbl (cap) (5)
(1)
(2)
(3)
(4)
(5)
Contract Price
Unless the monthly WTI price averages over US$111.00/bbl every day for the entire month, in which case the cap becomes US$90.00/bbl.
Unless the monthly WTI price averages over US$113.25/bbl every day for the entire month, in which case the cap becomes US$92.00/bbl.
Unless the monthly WTI price averages over US$116.25/bbl every day for the entire month, in which case the cap becomes US$92.00/bbl.
Unless the monthly WTI price averages over US$118.00/bbl every day for the entire month, in which case the cap becomes US$100.00/bbl.
Unless the monthly WTI price averages over US$106.00/bbl every day for the entire month, in which case the cap becomes US$90.00/bbl.
Foreign Currency Exchange Rate Risk
Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes
in foreign exchange rates. The Company does not sell or transact in any foreign currency, but may be affected by foreign
currency exchange rate changes related to commodity prices as outlined above as well as in relation to the crude oil
contracts, which are priced in U.S. dollars. As at December 31, 2012, the Company had the following foreign currency
exchange risk management contracts to mitigate these risks:
Period
Pricing Point
(Cdn$/US$)
Currency
Type of Contract
Quantity
Jan. 1/12 – Dec. 31/13
US$
Average Rate Range
Bonus Accumulator
US$700,000
Target – $1.10
Cdn$/US$ + $1,000
bonus/day (1)
June 1/12 – Dec. 31/13
US$
Average Rate Range
Bonus Accumulator
US$900,000
Target – $1.0775
Cdn$/US$ + $900
bonus/day (2)
(1)
The Company can earn a bonus payout of up to $1,000 per day depending on the period in which the exchange rate remains in the applicable range of
equal to or greater than $0.9350 and equal to or less than $1.10.
(2) The Company can earn a bonus payout of up to $900 per day depending on the period in which the exchange rate remains in the applicable range of
equal to or greater than $0.9300 and equal to or less than $1.0775.
76
DeeThree Exploration Ltd.
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
Company is exposed to interest rate risk to the extent the changes in market interest rates will impact its floating-rate
debts. As at December 31, 2012, the Company had approximately $63,104,000 drawn on the credit facility. As at
December 31, 2012, a 1% increase in interest rates would have resulted in a $286,000 decrease in net income before
income taxes (December 31, 2011 – $nil). As at December 31, 2012, a 1% decrease in interest rates would have resulted
in a $265,000 increase in net income before income taxes (December 31, 2011 – $nil).
(b) Capital Management
The Company’s policy is to maintain a strong but flexible capital structure so as to maintain investor, creditor and market
confidence and to sustain future development of the business. The Company manages its capital structure and adjusts
it in light of changes in economic conditions. The Company, upon approval from its Board of Directors, will balance its
overall capital structure through issuance of new shares or additional debt, or by undertaking other activities as deemed
appropriate under the circumstances. The capital structure of the Company consists of bank debt and shareholders’
equity comprising issued share capital, contributed surplus and deficit.
The following summarizes the Company’s capital structure:
As at December 31,
(000s)
Bank debt
Shareholders’ equity
2012
2011
($)
($)
63,104
212,090
8,521
167,568
In order to maintain or adjust its capital structure, DeeThree may issue new common shares, issue new debt, adjust
exploration and development capital expenditures or acquire or dispose of assets.
To facilitate its capital management, the Company prepares annual capital expenditure budgets which are updated as
necessary in light of varying factors including: current economic conditions, the risk characteristics of the Company’s
petroleum and natural gas assets, the Company’s inventory of investment opportunities, current and forecast net debt,
current and forecast commodity prices, and other factors that influence commodity prices and funds from operations,
such as quality and basis differentials, royalties and operating costs. The Company will continually evaluate available
sources of funds to finance its capital expenditures and may from time to time issue new equity if available on favourable
terms or seek additional debt financing at levels consistent with its policy of optimizing the cost of capital.
There were no changes in the Company’s approach to capital management during the year ended December 31, 2012.
17. Related Parties
The following summarizes the Company’s related-party transactions as at December 31, 2012:
The Company has retained a law firm to provide legal services. The Corporate Secretary of DeeThree is a partner of this
firm. During the year ended December 31, 2012, the Company incurred $570,000 with the firm (2011 – $475,000), included
in general and administrative expenses and share issuance costs, of which $22,000 remained in accounts payable at
December 31, 2012 (2011 – $12,000). Services provided related to advice and counsel primarily in the areas of general legal,
corporate governance and banking matters. The Company expects to continue using this firm in 2013.
All related-party transactions were in the normal course of operations and have been measured at exchange amounts
established and agreed to by the related parties and which are similar to those that the Company would expect to have
negotiated with third parties in similar circumstances.
2012 Annual Report
77
18. Commitments
Years Ended December 31,
2013
2014
2015
2016+
Total
($)
($)
($)
($)
($)
Operating lease – office
Operating lease – equipment
Exploration expenditures (flow-through)
Drilling contracts
Bank debt
640
294
19,052
4,836
63,104
640
48
–
–
–
640
–
–
–
–
160
–
–
–
–
2,080
342
19,052
4,836
63,104
Total
87,926
688
640
160
89,414
(000s)
As at December 31, 2012, the Company had contractual obligations for its office leases totalling approximately $2,080,000
to March 2016. The head office lease obligations are comprised of the lease payments as well as parking and an estimate
of occupancy costs of the Company’s head office space. The Company also had contractual obligations for several vehicles
and equipment totalling approximately $342,000 to May 2014.
In connection with the issuance of flow-through shares by the Company during the first quarter of 2012, DeeThree is required
to spend $17,253,450 of eligible exploration expenditures by December 31, 2013. As at December 31, 2012, $3,206,000 of
these have been incurred. The remaining $14,047,450 will be incurred during 2013. These expenditures will be renounced to
shareholders in January 2013 effective December 31, 2012.
In connection with the issuance of flow-through shares by the Company during the fourth quarter of 2012, DeeThree is required
to spend an additional $5,005,000 of eligible exploration expenditgures by December 31, 2013. As at December 31, 2012,
$nil of these have been incurred. They will be incurred during 2013 and renounced to shareholders in January 2013 effective
December 31, 2012.
DeeThree has two contracts for drilling rig services under which the Company is committed to using services totalling
$4,836,000 extending into 2013.
At December 31, 2012, the Company also had the obligation to repay the amount outstanding on the revolving demand credit
facility, which was drawn to $63,104,000 at period-end.
During the year, DeeThree entered into a farm-in agreement with a senior oil and natural gas producer pursuant to which it
may earn 100 percent working interest in up to 34 additional sections of Belly River petroleum and natural gas rights directly
offsetting DeeThree’s Brazeau property. DeeThree is committed to drilling a minimum of three horizontal wells on the farm-in
lands with a continuing rolling option thereafter in return for a 15 percent non-convertible overriding royalty.
19. Subsequent Events
On January 18, 2013, the Company executed a purchase and sale agreement with an oil and natural gas company pursuant
to which DeeThree acquired interests in producing assets in the Peace River Arch area for consideration of approximately
$2,100,000 subject to certain adjustments.
On February 19, 2013, the Company issued 4,420,000 common shares at a price of $6.80 per share for total gross proceeds
of $30,056,000 ($27,952,000 net of estimated share issuance expenses). The proceeds of the share offering will be used to
conduct development activity on the Company’s Ferguson and Brazeau properties.
On March 12, 2013, the Company issued 663,000 common shares at $6.80 per share for total gross proceeds of $4,508,400
($4,192,800 net of estimated share issuance expenses) on the exercise in full of the underwriters’ over-allotment option from
the February issuance.
78
DeeThree Exploration Ltd.
CORPORATE GOVERNANCE
Corporate Responsibility
Corporate responsibility is DeeThree’s commitment to understanding that the economic, social and environmental choices it
makes as a corporation affects its shareholders, employees and communities in which it operates. Consequently, we are dedicated
to operating our business ethically and according to the principles of honesty, transparency and accountability. Corporate
responsibility is integral to the long-term business growth and success of DeeThree.
Our Company’s priorities for corporate responsibility include:
Ethics
DeeThree’s code of business conduct and ethics establishes the Company’s commitment to conducting its business ethically and
legally. The Code provides a framework for identifying how to deal with each other, shareholders, employees, communities and
competitors as well as making ethical business decisions that adhere to these commitments.
Employees
The Company endeavours to build a fair, diverse and inclusive workplace that reflects the communities it serves and that attracts
and retains extraordinary people, while creating opportunities for their continued development.
Community Development
DeeThree is dedicated to contributing to the economic and social development of the diverse communities in which it operates.
Our Company strives to make a positive impact in each of our operating areas and where our employees live and work.
Environment
We are committed to be an environmental leader in the Canadian oil and gas industry. DeeThree is working to make a positive
environmental impact through its operations and its employees.
Corporate Governance
Corporate responsibility is a key component of DeeThree’s business strategy and is managed within a framework of internal
control, governance and risk management processes. While the Company’s Board of Directors is responsible for setting the
tone for a culture of integrity and compliance throughout DeeThree, it is the Company’s Chief Executive Office and its Corporate
Governance and Compensation Committee that has primary responsibility for ensuring DeeThree acts as an exemplary
corporate citizen.
The past year has seen a number of new reporting requirements set out by the International Accounting Standards Board.
DeeThree is committed to meeting and exceeding the new requirements as well as continuing to monitor its internal systems to
ensure the Company’s reporting is of the highest standards.
2012 Annual Report
79
COMMITTEES OF THE BOARD
Audit Committee
Committee Members: H. Hamm, D. Nerland, B. Porter
Responsible for oversight of the nature and scope of the annual audit, management’s reporting on internal accounting standards and
practices, financial information and accounting systems and procedures, financial reporting and statements, and recommending,
for Board approval, the audited financial reports and other mandatory disclosure releases containing financial information. The
Committee assists the Board in respect of the preparation and disclosure of the financial reports and related matters; provides
an open avenue of communication among the Company’s Board, auditors, financial and senior management; and, ensures the
external auditors’ independence, and reviews and appraises their performance. The Committee’s objective is to increase the
credibility and objectivity of the Company’s financial reports and to strengthen the role of the outside directors by facilitating
in- depth discussions between directors on the Committee, management and external auditors.
Corporate Governance & Compensation Committee
Committee Members: H. Hamm, D. Nerland, B. Porter
In respect of corporate governance matters, the Committee develops and monitors the Company’s general approach to corporate
governance issues; proposes changes as necessary to respond to governance recommendations or guidelines from regulatory
authorities and ensures that all appropriate or necessary governance systems remain in place and are periodically reviewed
for effectiveness. The Committee is responsible for developing clear position descriptions for the Chairman of the Board, and,
together with the Chief Executive Officer (“CEO”), developing a clear position description for the CEO, which includes delineating
management’s responsibilities and developing the corporate goals and objectives that the CEO is responsible for meeting;
assessing the Board, its committees and each director in respect of effectiveness and contribution; developing a written code of
business conduct and ethics that is applicable to all directors, officers and employees of the Company; developing and monitoring
the Company’s policies related to the prospective recruitment and recommendation of new Board members; and, periodically
considering the need for special policies of the Company in unique or emerging policy areas such as corporate ethics, gender
equality and sexual harassment.
In respect of compensation matters, the Committee reviews and provides recommendations to the Board on compensation
policies and guidelines for employees of the Company as well as corporate benefits, bonuses and other incentives, including stock
options. The Committee reviews and approves corporate goals and objectives relevant to the CEO’s compensation, evaluates
the CEO’s performance in light of those goals and objectives; provides recommendations for compensation of non CEO officer
and director compensation, incentive compensation plans and equity based plans; succession planning for the officers and
key employees of the Company; and, any material changes or trends in human resources policy, procedure, compensation
and benefits.
Reserves Committee
Committee Members: H. Hamm, D. Nerland, B. Porter
Responsible for reviewing the procedures relating to the disclosure of information with respect to oil and gas activities, including
its procedures for complying with the disclosure requirements and restrictions of NI 51-101, as well as the appointment of the
independent evaluator and the Company’s procedures for providing information to the independent evaluator who reports on
reserves data for the purposes of NI 51-101. The Committee meets with management and the independent evaluator in order to
determine whether any restrictions affect the ability of the independent evaluator to report on the reserves data without reservation,
reviews the reserves data and related report of the independent evaluator as well as reviews the annual filings required by
NI 51-101 and recommending approval of the contents and filings to the Board.
80
DeeThree Exploration Ltd.
CORPORATE INFORMATION
Board of Directors
Head Office
Abbreviations
Michael Kabanuk
Independent Businessman
Suite 2200
520 Third Avenue S.W.
Calgary, Alberta T2P 0R3
Telephone:
403-767-3060
Facsimile:
403-263-9710
Website:
www.deethree.ca
bbls
boe
GJ
/d
mbbls
mboe
Martin Cheyne
Auditors
President & Chief Executive Officer
DeeThree Exploration Ltd.
KPMG LLP
Executive Chairman
DeeThree Exploration Ltd.
Brendan Carrigy
Calgary, Alberta
Henry Hamm (1)(2)(3)
mcf
mm
mmbtu
mmcf
NGLs
barrels
barrels of oil equivalent
gigajoules
per day
thousand barrels
thousand barrels of oil
equivalent
thousand cubic feet
million
million British thermal units
million cubic feet
natural gas liquids
Independent Businessman
Banker
Dennis Nerland (1)(2)(3)
National Bank of Canada
Conversion of Units
Partner
Shea Nerland Calnan LLP
Calgary, Alberta
Brad Porter (1)(2)(3)
Calgary, Alberta
1.0 mcf
1.0 mcf
1.0 acre
2.5 acres
1.0 bbl
6.29 bbls
1.0 foot
3.281 feet
1.0 mcf
0.035 mcf
1.0 mile
0.62 miles
ATB Financial
Independent Businessman
(1)
Audit Committee Member
(2)
Reserves Committee Member
(3)
Corporate Governance & Compensation
Committee Member
Officers
Martin Cheyne
President & Chief Executive Officer
Evaluation Engineers
Sproule Associates Limited
Calgary, Alberta
Legal Counsel
Davis LLP
Calgary, Alberta
Gail Hannon
Registrar and Transfer Agent
Chief Financial Officer
Olympia Trust Company
Trevor Murray
Calgary, Alberta
Vice President, Land
Clayton Thatcher
Vice President, Exploration
Casey Paulhus
Controller
Daniel Kenney
Corporate Secretary
Stock Trading
Toronto Stock Exchange
Trading Symbol: DTX
OTCQX
Trading Symbol: DTHRF
=
=
=
=
=
=
=
=
=
=
=
=
1.02 mmbtu
1.05 GJ
0.40 hectares
1.0 hectare
0.159 cubic metres
1.0 cubic metre
0.3048 metres
1.0 metre
28.2 cubic metres
1.0 cubic metre
1.61 kilometres
1.0 kilometre
Natural gas is equated to oil on the
basis of 6 mcf : 1 bbl
2200, 520 – 3rd Ave SW
Calgary, AB T2P 0R3
Phone: 403-767-3060
Fax: 403-263-9710
www.deethree.ca