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CALGARY, Aug. 12, 2019 /CNW/ - Surge Energy Inc. ("Surge"
or the "Company") (TSX: SGY) is pleased to announce its financial
and operating results for the quarter ended June 30, 2019.
MESSAGE TO THE SHAREHOLDERS
Q2/19 was an excellent quarter for Surge. Production and
adjusted funds flow1 came in higher than analyst
estimates2; and the Company's bank debt, net
debt1, operating expenses, transportation expenses, and
general and administrative costs all came in lower than budgeted
expectations3.
Production of 21,544 boepd in Q2/19 averaged more than Surge's
2019 exit rate guidance of 21,500 boepd, which represents an
increase of 26 percent over Q2/18 at 17,072 boepd.
Surge was originally guiding to exit 2019 with production of
22,000 boepd; however, the Company sold a 490 boepd non-core asset
in Q1/19 for net cash proceeds of $28.1
million, resulting in new 2019 production exit rate guidance
of 21,500 boepd.
Drilling results from Surge's Q2/19 program exceeded
management's expectations. Successful drilling in Q2/19 at the
Company's Sparky, Shaunavon and
Valhalla core areas has resulted
in current estimated production additions of 1,625 bopd, for total
exploration and development expenditures of $25.2 million, providing capital
efficiencies4 of approximately $15,877 per bopd.
HIGHLIGHTS
- Surge's Q2/19 quarterly production of 21,544 boepd increased by
26 percent over Q2/18 production of 17,072 boepd.
- Adjusted funds flow in Q2/19 was $50.7
million, an increase of 31 percent as compared to Q2/18 at
$38.6 million.
- Cash flow from operating activities in Q2/19 was $45.8 million, an increase of 36 percent as
compared to Q2/18 at $33.7
million.
- The Company's operating netback1 increased by six
percent, to $31.24 per boe in Q2/19,
from $29.46 per boe in Q2/18.
- The Company's operating expenses for Q2/19 were $14.43 per boe and net operating
expenses1 were $14.03 per
boe, compared to 2019 guidance of $14.95 - $15.45 per
boe.
- The Company generated $17.7
million of adjusted funds flow1 in the quarter in
excess of exploration and development expenditures and dividends
paid.
- Surge paid dividends of $7.9
million in Q2/19, representing 15 percent of Q2/19 adjusted
funds flow.
- The Company maintained a net debt to annualized Q2/19 adjusted
funds flow ratio1 of under two times (1.9x).
- Surge closed a small, miscellaneous gross overriding royalty
("GORR") disposition of 214 boepd on June
28, 2019, for net cash proceeds of $29.1 million – providing sale metrics of greater
than $135,000 per flowing boepd.
- Subsequent to June 30, 2019,
pursuant to a Crown sale on July 31,
2019, Surge successfully acquired an additional 8.5 sections
of highly prospective Sparky acreage at Betty Lake – extending the
Company's large new Sparky discovery to the north.
- Subsequent to June 30, 2019,
pursuant to a Crown sale on July 31,
2019, Surge successfully acquired an additional 9.5 sections
of highly prospective acreage at Nipisi South in the Company's
Greater Sawn core area. This new land is immediately offsetting
existing Surge light oil production, and is prospective for both
Slave Point and Clearwater oil
reserves and production.
FINANCIAL AND OPERATING SUMMARY
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
($1000s except per
share amounts)
|
|
2019
|
2018*
|
%
Change
|
|
2019
|
2018*
|
%
Change
|
Financial
highlights
|
|
|
|
|
|
|
|
|
Oil sales
|
|
104,387
|
83,516
|
25 %
|
|
195,515
|
148,008
|
32 %
|
NGL sales
|
|
1,649
|
2,486
|
(34)%
|
|
4,074
|
4,947
|
(18)%
|
Natural gas
sales
|
|
1,629
|
1,092
|
49 %
|
|
5,944
|
2,429
|
145 %
|
Total oil, natural
gas, and NGL revenue
|
|
107,665
|
87,094
|
24 %
|
|
205,533
|
155,384
|
32 %
|
Cash flow from
operating activities
|
|
45,807
|
33,725
|
36 %
|
|
74,715
|
57,940
|
29 %
|
Per share - basic
($)
|
|
0.15
|
0.15
|
3 %
|
|
0.24
|
0.25
|
(4)%
|
Adjusted funds
flow
|
|
50,742
|
38,596
|
31 %
|
|
92,593
|
66,765
|
39 %
|
Per share - basic
($)
|
|
0.16
|
0.17
|
(6)%
|
|
0.30
|
0.29
|
3 %
|
Total exploration and
development expenditures
|
|
25,197
|
23,344
|
8 %
|
|
66,458
|
58,253
|
14 %
|
Total acquisition and
dispositions
|
|
(29,166)
|
28,939
|
(201)%
|
|
(56,973)
|
22,454
|
(354)%
|
Total capital
expenditures
|
|
(3,969)
|
52,283
|
(108)%
|
|
9,485
|
80,707
|
(88)%
|
Net debt, end of
period
|
|
391,020
|
276,140
|
42 %
|
|
391,020
|
276,140
|
42 %
|
|
|
|
|
|
|
|
|
|
Operating
highlights
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (bbls per
day)
|
|
17,366
|
13,343
|
30 %
|
|
17,454
|
12,897
|
35 %
|
NGLs (bbls per
day)
|
|
727
|
556
|
31 %
|
|
685
|
558
|
23 %
|
Natural gas (mcf per
day)
|
|
20,706
|
19,038
|
9 %
|
|
20,685
|
18,585
|
11 %
|
Total (boe per day)
(6:1)
|
|
21,544
|
17,072
|
26 %
|
|
21,587
|
16,553
|
30 %
|
Average realized
price (excluding hedges):
|
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
|
66.05
|
68.78
|
(4)%
|
|
61.89
|
63.40
|
(2)%
|
NGL ($ per
bbl)
|
|
24.93
|
49.15
|
(49)%
|
|
32.84
|
48.99
|
(33)%
|
Natural gas ($ per
mcf)
|
|
0.86
|
0.63
|
37 %
|
|
1.59
|
0.72
|
121 %
|
|
|
|
|
|
|
|
|
|
Netback ($ per
boe)
|
|
|
|
|
|
|
|
|
Petroleum and natural
gas revenue
|
|
54.92
|
56.06
|
(2)%
|
|
52.60
|
51.86
|
1 %
|
Realized gain (loss)
on financial contracts
|
|
(1.29)
|
(2.46)
|
(48)%
|
|
(0.83)
|
(1.81)
|
(54)%
|
Royalties
|
|
(7.03)
|
(8.36)
|
(16)%
|
|
(6.36)
|
(7.32)
|
(13)%
|
Net operating
expenses
|
|
(14.03)
|
(14.16)
|
(1)%
|
|
(14.58)
|
(14.37)
|
1 %
|
Transportation
expenses
|
|
(1.33)
|
(1.62)
|
(18)%
|
|
(1.66)
|
(1.45)
|
14 %
|
Operating
netback
|
|
31.24
|
29.46
|
6 %
|
|
29.17
|
26.91
|
8 %
|
G&A
expense
|
|
(1.86)
|
(2.06)
|
(10)%
|
|
(1.82)
|
(2.14)
|
(15)%
|
Interest
expense
|
|
(3.48)
|
(2.56)
|
36 %
|
|
(3.66)
|
(2.50)
|
46 %
|
Adjusted funds
flow
|
|
25.90
|
24.84
|
4 %
|
|
23.69
|
22.27
|
6 %
|
|
|
|
|
|
|
|
|
|
Common shares
outstanding, end of period
|
|
314,051
|
230,494
|
36 %
|
|
314,051
|
230,494
|
36 %
|
Weighted average
basic shares outstanding
|
|
314,010
|
230,812
|
36 %
|
|
311,742
|
231,904
|
34 %
|
Stock option
dilution
|
|
—
|
5,265
|
(100)%
|
|
—
|
4,407
|
(100)%
|
Weighted average
diluted shares outstanding
|
|
314,010
|
236,077
|
33 %
|
|
311,742
|
236,311
|
32 %
|
|
*IFRS 16 was adopted
January 1, 2019 using the modified retrospective approach and as
such, comparative information for 2018 that may have been impacted
has not been restated. Refer to the Changes in Accounting Policies
section of the MD&A for additional information
|
OPERATIONAL HIGHLIGHTS
In Q2/19, Surge successfully drilled 9 gross (9 net) producing
wells, currently producing an estimated 1,625 bopd, for total
exploration and development expenditures of $25.2 million ($15,877 per bopd).
These excellent results are a continuation of the operational
momentum, and track record Surge has generated over the last 12
financial quarters – growing production by 77 percent from 12,182
boepd (78 percent liquids) in Q2/16, to 21,544 boepd (84 percent
liquids) in Q2/19.
Sparky Core Area
Cost Reductions From First Four Well Pad
In Q2/19, Surge drilled and completed 4 gross (4.0 net) wells in
its Sparky core area.
At Provost, Surge drilled four excellent Sparky wells on the
Company's first ever four well drilling pad. Due to pad drilling
efficiencies, the average "all-in" cost at Provost was $1.04 million per well, compared to budget of
$1.25 million per well. The
four wells combined are currently producing over 675 bopd. Surge
has more than 35 net drilling locations5 remaining at
the Company's large, internally estimated 90 million net
OOIP6, Sparky pool at Provost. As a result of Surge's
drilling results at Provost, operating expenses in this area are
now $6.75 per boe.
Approximately 18 months ago, Surge announced a large, new Sparky
oil discovery at Betty Lake (near Wainwright, Alberta). The OOIP at Betty
Lake is estimated to be over 80 million net barrels. Surge has now
largely "de-risked" the Company's Betty
Lake Sparky oil pool, drilling eight consecutive horizontal
wells, with 100 percent success. Surge estimates that there are
more than 50 net locations5 remaining to drill at
Betty Lake, with full waterflood upside7. Based on
Surge's excellent drilling results at Betty Lake, operating costs
in this field are now $7.00 per
boe.
In addition, at a recent Crown sale on July 31, 2019, Surge successfully acquired an
additional 8.5 sections of land at Betty Lake – extending this
large Sparky pool to the north. The Company believes that this
acreage comprises a large Sparky oil pool extension, adding up to
an estimated 40 million barrels of net OOIP, and up to 38
additional net drilling locations5.
The Company is also experiencing consistently strong results at
its Sparky MM pool at Sounding Lake, with Surge's three most recent
wells producing above the Sparky type curve (which has an IP 30 of
100 bopd). Surge estimates more than 30
locations5 remaining to be drilled at this large,
25 million OOIP, 31 degree API Sparky asset.
Surge anticipates drilling up to 14 locations in the Sparky core
area in 2H/19.
Rapidly Expanding Core Area
In less than five years, in Surge's Sparky core area the Company
has amassed more than 900,000,000 barrels of estimated net OOIP,
production of over 7,750 boepd (90 percent oil), and over 450
drilling locations - providing a 13 year drilling inventory (at the
Company's current pace of 35 Sparky drills per year).
Surge's high quality Sparky reservoirs are characterized as
conventional, large OOIP per section (>6mm barrels per section),
low risk, shallow, sandstone reservoirs, at 700-800 meters depth.
The wells are highly economic, delivering over 135,000 boe (90
percent oil) internally estimated ultimate recovery ("EUR"), for
primary production only, at an "all-in" cost of less than
$1.2 million per well - drilled,
completed and onstream.
Surge's Sparky type curve wells pay out in less than a year, and
deliver profit to investment ratios[8] of over 2.0 at current strip
oil pricing of US $54 WTI per barrel,
for primary drilling. In addition, Surge has successfully proven
waterflood upside for the Company's Sparky/Lloyd plays at:
Wainwright, Eyehill, Sounding Lake
MM, Provost, Macklin, Lakeview, and Silver.
Surge is now utilizing the following technological improvements
and efficiencies that the Company's experienced and proven Sparky
technical team have integrated over the last 4-5 years:
- Longer horizontal wells;
- Monobore drilling;
- Increased number of frac stages;
- Less frac intensity per stage;
- Floating in the casing;
- Cemented liner;
- Multi cycle frac sleeves vs "ball-drop" system;
- Modified mud system; and
- Pad drilling.
Given these exciting improvements in the Company's drilling and
completion processes, Surge has now driven the cost of a Sparky
well down from a high of $2.3 million
in 2014, to approximately $1.0
million for the Company's two most recent pad wells at
Provost. In addition, Surge has also increased the Company's
internally generated Sparky type curve production estimates
significantly over this period (i.e. by as much as 25-30
percent).
By drilling 105 (out of 106) successful, highly economic,
horizontal wells in Surge's Sparky core area over the last five
years, the Company has now proven that its proprietary
drilling/completion systems deliver excellent results, with
remarkable consistency. Management believes this bodes very well
for the continued growth and development of Surge's rapidly
expanding Sparky play.
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Eyehill – A Case Study
An illustration of Surge's track record for adding value in its
Sparky core area is at the Company's high quality, 170 million net
OOIP, 29 degree API oil asset at Eyehill.
Over the last four years at Eyehill, Surge has: 1) aggressively
grown the asset - adding significant value; and 2) strategically
transitioned the property into a sustainable, long life,
waterflooded asset, as set forth within the Eyehill Production
Growth section:
Eyehill – Production Growth > 380 Percent in 3
Years
- Increased production 380 percent in three years.
- Of the 63 operated horizontal wells at Eyehill, Surge drilled
51 and acquired 12.
- Peak production of 2,950 boepd was reached in May 2017.
- Surge had only 15 horizontal wells producing 500 boepd (80
percent liquids) at year end 2015.
- Surge has drilled an average of 14 wells per year (12 per year
excluding acquisitions), increasing production significantly –
inclusive of lost production associated with water injector
conversions.
To date seven of the 63 wells drilled have now been converted to
water injection at Eyehill, providing pressure support and lowering
the production decline for this large, conventional Sparky oil pool
(i.e. lower annual declines fit very well with Surge's growth and
dividend paying business model).
Eyehill - Production Profile (Low Decline Waterflood)
Based on Surge's strong drilling and waterflood results at
Eyehill, operating expenses are now $7.50 per boe.
Eyehill – Value Creation
|
Net OOIP
(mmbbl)
|
# of
producing
Hz's
|
# of Hz
Wtr
Injectors
|
Production
(boepd)
|
%
Oil
|
TPP
|
TPP
|
Reserves
(Mboe)
|
NPV10
($
millions)
|
YE
2015
|
70
|
15
|
1
|
500
|
80%
|
4,089
|
$49
|
YE
2018
|
170
|
56
|
7
|
2,400
|
81%
|
13,305
|
$242
|
3 Yr
Change
|
100
|
41
|
6
|
1,900
|
1%
|
9,216
|
$193
|
|
143%
|
273%
|
|
380%
|
|
225%
|
395%
|
In the last three years Surge has increased the Company's
Sproule NPV10 Total Proved plus Probable reserve value at Eyehill
by 395 percent; from $49 million to
$242 million.
Surge will continue to follow this proven, disciplined operating
strategy of delivering higher initial drilling growth and value
creation, followed by strategically transitioning the Company's
high quality, large OOIP, Sparky sandstone reservoirs into
waterfloods (to deliver long term adjusted funds flow in excess of
exploration and development expenditures, and excellent profit to
investment ratios) at: Eyehill, Betty Lake, Provost, Sounding MM,
Sounding East, Lakeview, Macklin, Cadogan and Eyehill South.
This conservative operating strategy is a key component of
Surge's growth plus dividend paying business model.
Valhalla Core Area
At Valhalla, in Q2/19 Surge
drilled a successful, 100 percent working interest, Doig horizontal
light oil well. This is Surge's third 200 meter horizontal in-fill
well drilled into the Doig reservoir, and further validates the
continued downspacing of this large, 150 million OOIP net, light
oil pool. This well is currently producing more than 750 boepd (70
percent light oil).
Surge estimates an inventory of more than 50 net light oil
locations5 at Valhalla in the Doig, Charlie Lake and Montney formations, providing a drilling
inventory of more than 10 years.
The Company anticipates drilling up to two locations at
Valhalla in 2H/19.
Shaunavon Core Area
In Q2/19 Surge drilled 4 gross (4.0 net) successful new wells at
Shaunavon. Two of the wells were
drilled in the Upper Shaunavon formation, and two were drilled in
the Lower Shaunavon formation. The Company also continued its
successful pump jack conversion program, with another 30 wells
converted to pumpjacks in 1H/19.
Surge estimates over 125 net drilling locations5 remaining
in the Upper and Lower Shaunavon formations, and over 400 million
barrels of estimated (combined) net OOIP. The Shaunavon field has a high operating netback,
is waterflooded, and delivers annual adjusted funds flow in excess
of exploration and development expenditures - which fits very well
with Surge's lower risk, lower decline, growth and dividend paying
business model.
Surge plans for the drilling of up to four additional locations
at Shaunavon in 2H/19.
Greater Sawn Core Area
At Greater Sawn, Surge continues to enjoy the significant free
adjusted funds flow from this 5,000 bopd light oil asset. The
Company drilled its first four wells at Sawn late last year, and
early this year, with 100 percent success.
Surge continues to optimize the successful waterflood at Sawn,
with plans to expand waterflood operations later this year, and
into 2020. Surge estimates a drilling inventory of over 10 years in
the Greater Sawn area, with more than 100 net
locations5 at this high quality, 600 million barrel
net OOIP, light oil asset.
Further to the above, at a recent Crown sale on July 31, 2019, Surge successfully acquired an
additional 9.5 sections of acreage at Nipisi South in the Company's
Greater Sawn core area. Surge believes Nipisi South contains up to
30 million barrels of net OOIP (light oil) in the Slave Point
formation, with over 20 additional net Slave Point drilling
locations5. The new acreage is also prospective for
Clearwater oil reserves and
production.
The Company anticipates drilling up to four locations at Greater
Sawn in 2H/19.
BANK LINE UPDATE
Surge's new borrowing base has been confirmed by its lenders at
$500 million, comprised of a
$450 million revolving line of
credit, and a $50 million operating
line of credit (with unanimous lender consent required for the
Company to draw in excess of $425
million). On this basis, Surge has over $105 million9 of unrestricted
liquidity available to the Company, and committed access to over
$180 million10 of
total liquidity.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
During the first half of 2019 the Company elected to participate
in the Alberta Energy Regulators ("AER") Area Based Closure program
("ABC program"). Building on the Company's work in Q1/19, Surge has
continued to efficiently direct capital towards abandoning and
reclaiming its non-core Cherry natural gas property.
The Company has seen abandonment and reclamation costs continue
to be approximately 55 percent of AER estimates, confirming Surge's
belief in the economies of scale that are found within the ABC
program. Given the Company's success in Q1/19 at Cherry, Surge has
now initiated ABC programs in a number of the Company's non-core
areas.
Surge has committed $6 million in
2019 to a proactive, well-funded, annual abandonment and
reclamation program. This exceeds AER mandated contributions by
over $1.8 million, and builds on the
$17 million the Company has spent
since 2014.
During 1H/19 the Company abandoned 76 wells. The Company has now
increased its target abandonment commitment for 2019 from 125 to
150 wells, which is approximately three times the number of wells
the Company plans to drill this year.
The Company also continued to advance its Social and Governance
leadership by further demonstrating its commitment to diversity in
the workplace and on the Board of Directors. Following the
Annual General Meeting, the percentage of female Directors on
Surge's Board of Directors increased to 33 percent from 22 percent
in Q3/18. The Company is pleased to not only have increased
gender diversity on the Board, but to have added three highly
qualified directors with diverse backgrounds, and proven track
records, in the past year.
As further evidence of Surge's commitment to Board diversity and
renewal, Surge's Board independence has increased to 78 percent in
Q2/19 from 71 percent in Q2/18; and the average age of Surge Board
members is currently 58 years, down from 62 years in Q2/18.
Surge is a supporter of community engagement and recognizes the
importance of supporting charitable organizations and the
communities in which the Company operates. Details on the Company's
recent community engagement initiatives can be found on Surge's
website at www.surgeenergy.ca.
OUTLOOK – CONSISTENT GROWTH; SUSTAINABLE DIVIDEND
Management's stated goal is to be the best positioned, top
performing, light/medium gravity crude oil growth and dividend
paying public company in its peer group in Canada.
Surge focuses on sustainability, balance sheet management, and
cost controls to deliver returns to Surge shareholders. The Company
continues to grow its production base, and 14 year drilling
location inventory, in its core areas of Sparky, Valhalla, Greater Sawn, and Shaunavon through low risk development
drilling, and waterfloods - in accordance with management's
detailed business plan. Surge also strategically applies growth
capital to high quality, large OOIP, core area acquisitions.
The Company has an excellent hedging program in place to protect
Surge's adjusted funds flow. For 2H/19, Surge has hedged 7,000
bbl/d of WTI crude oil with an average floor price of CAD
$78/bbl. This represents
approximately 50 percent of Surge's forecasted after royalty crude
oil production for 2H/19. Surge has also retained upside to further
WTI price increases on 55 percent of the hedged volumes, with an
average ceiling of CAD $103/bbl.
On this basis, Surge continues to pay the Company's monthly
cash dividend (currently 8 percent yield11). Surge
targets dividend payments that range from 20 to 30 percent of
adjusted funds flow. Surge paid dividends of $7.9 million in Q2/19, which equates to 15
percent of Q2/19 adjusted funds flow.
APPOINTMENT OF CHIEF FINANCIAL OFFICER - MR. JARED DUCS
Surge is also pleased to announce the promotion of Mr.
Jared Ducs to the office of Chief
Financial Officer of the Company effective August 9, 2019. Mr. Ducs has been the Vice
President, Finance, of Surge since August
16, 2018, and has been with Surge for over 9 years.
"Jared has been a leader at Surge for many years. His extensive
financial, operational, and strategic experience will continue to
be a huge asset for the Company," says Surge President and CEO,
Paul Colborne.
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FORWARD LOOKING
STATEMENTS:
This press release contains forward-looking statements. The use
of any of the words "anticipate", "continue", "estimate", "expect",
"may", "will", "project", "should", "believe" and similar
expressions are intended to identify forward-looking statements.
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.
More particularly, this press release contains statements
concerning: Management's expectations and plans with respect to the
development of its assets and the timing thereof, including its
drilling and enhanced recovery plans; Surge's assets and the risks
and characteristics associated therewith; Surge's declared focus
and primary goals; Surge's dividend policy and sustainability
thereof, Surge's plans to grow the monthly dividend; participation
in the ABC program and the anticipated benefits therefrom; Surge's
plans to abandon certain properties and the timing and benefits
thereof, Surge's abandonment and reclamation program and budget;
Surge's hedging program; liquidity available to Surge under its
credit facility; Surge's decline rates, reserve life index,
estimated ultimate recovery, drilling costs and locations, profit
to investment ratios, OOIP, estimated 2019 exploration and
development capital budget, estimated 2019 net operating, G&A
and transportation costs, 2019 production exit rate guidance; and
the anticipated benefits of Surge's operational and financial
corporate fundamentals.
The forward-looking statements are based on certain key
expectations and assumptions made by Surge, including expectations
and assumptions the performance of existing wells and success
obtained in drilling new wells; anticipated expenses, cash flow and
capital expenditures; the application of regulatory and royalty
regimes; prevailing commodity prices and economic conditions;
development and completion activities; the performance of new
wells; the successful implementation of waterflood programs; the
availability of and performance of facilities and pipelines; the
geological characteristics of Surge's properties; the successful
application of drilling, completion and seismic technology; the
continued availability of Surge's credit facility; the
determination of decommissioning liabilities; prevailing weather
conditions; exchange rates; licensing requirements; the impact of
completed facilities on operating costs; the ability of Surge to
maintain and/or increase its dividend; the availability and costs
of capital, labour and services; and the creditworthiness of
industry partners.
Although Surge believes that the expectations and assumptions on
which the forward-looking statements are based are reasonable,
undue reliance should not be placed on the forward-looking
statements because Surge can give no assurance that they will prove
to be correct. Since forward-looking statements address future
events and conditions, by their very nature they involve inherent
risks and uncertainties. Actual results could differ materially
from those currently anticipated due to a number of factors and
risks. These include, but are not limited to, risks associated with
the oil and gas industry in general (e.g., operational risks in
development, exploration and production; delays or changes in plans
with respect to exploration or development projects or capital
expenditures; the uncertainty of reserve estimates; the uncertainty
of estimates and projections relating to production, costs and
expenses, and health, safety and environmental risks), commodity
price and exchange rate fluctuations and constraint in the
availability of services, adverse weather or break-up conditions,
uncertainties resulting from potential delays or changes in plans
with respect to exploration or development projects or capital
expenditures; or failure to obtain the continued support of the
lenders under Surge's bank line. Certain of these risks are set out
in more detail in Surge's Annual Information Form dated
March 14, 2019 and in Surge's
MD&A for the period ended December 31,
2018, both of which have been filed on SEDAR and can be
accessed at www.sedar.com.
The forward-looking statements contained in this press release
are made as of the date hereof and Surge undertakes no obligation
to update publicly or revise any forward-looking statements or
information, whether as a result of new information, future events
or otherwise, unless so required by applicable securities laws.
Reserves Data
Boe means barrel of oil equivalent on the basis of 1 boe to
6,000 cubic feet of natural gas. Boe may be misleading,
particularly if used in isolation. A boe conversion ratio of 1 boe
for 6,000 cubic feet of natural gas is based on an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
Boe/d and boepd means barrel of oil equivalent per day. Bbl means
barrel of oil. NGLs means natural gas liquids.
Original Oil in Place ("OOIP") means Discovered Petroleum
Initially In Place ("DPIIP"). DPIIP is derived by Surge's internal
Qualified Reserve Evaluators ("QRE") and prepared in accordance
with National Instrument 51-101 and the Canadian Oil and Gas
Evaluations Handbook ("COGEH"). DPIIP, as defined in COGEH, is that
quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations prior to production. The
recoverable portion of DPIIP includes production, reserves and
Resources Other Than Reserves (ROTR). OOIP/DPIIP and potential
recovery rate estimates are based on current recovery technologies.
There is significant uncertainty as to the ultimate recoverability
and commercial viability of any of the resource associated with
OOIP/DPIIP, and as such a recovery project cannot be defined for a
volume of OOIP/DPIIP at this time.
Drilling Locations
This press release discloses drilling locations in two
categories: (i) booked locations; and (ii) unbooked locations.
Booked locations are proved locations and probable locations
evaluated by Sproule. Unbooked locations are generated internally
by Qualified Reserve Evaluators using standard practices as
prescribed in the Canadian Oil and Gas Evaluations Handbook.
Unbooked locations are internal estimates based on prospective
acreage and assumptions as to the number of wells that can be
drilled per section based on industry practice and internal review.
Unbooked locations do not have attributed reserves or resources.
Unbooked locations have been identified by Surge's internal
certified Engineers and Geologists (who are also Qualified Reserve
Evaluators) as an estimation of our multi-year drilling activities
based on evaluation of applicable geologic, seismic, engineering,
production and reserves information. There is no certainty that the
Company will drill all unbooked drilling locations and if drilled
there is no certainty that such locations will result in additional
oil and gas reserves, resources or production. The drilling
locations on which the Company actually drills wells will
ultimately depend upon the availability of capital, regulatory
approvals, seasonal restrictions, oil and natural gas prices,
costs, actual drilling results, additional reservoir information
that is obtained and other factors. While certain of the unbooked
drilling locations have been de-risked by drilling existing wells
in relative close proximity to such unbooked drilling locations,
the majority of other unbooked drilling locations are farther away
from existing wells where management has less information about the
characteristics of the reservoir and therefore there is more
uncertainty whether wells will be drilled in such locations and if
drilled there is more uncertainty that such wells will result in
additional oil and gas reserves, resources or production.
All drilling locations (booked and unbooked) are further
evaluated internally by Surge on an annual basis, and are
constructed using a representative, factual and balanced analog
data set. The type curve EUR is measured against OOIP
calculations to ensure reasonable recovery factors have been
achieved. Type curves are developed by Surge's internal QRE
and fully comply with Part 5.8 of the Companion Policy 51 –
101CP. Type curve metrics referenced on page 4 & 5 of the
press release are derived by using a Surge Sparky type curve which
was run on July 30 strip pricing and
the 5 year average WCS differential (US$56.62/bbl WTI, US$15.70/bbl WCS differential, 0.761 FX).
Assuming the December 31, 2018
reference date as noted per the Sproule Reserves report and
excluding locations associated with the non-core disposition date
March 28, 2019, Surge has over 800
net drilling locations identified herein, of which over 420 are
unbooked locations and 389 net are booked locations. Of the 389 net
booked locations identified herein, 297 net are Proved locations
and 91 net are Probable locations. The Company's Sparky core area
has 136 net booked locations, of which 100 net are Proved locations
and 36 net are Probable locations. Betty Lake locations identified
herein has 12 net booked Proved locations and 7 net booked Probable
locations. Provost locations identified herein has 15 net
booked Proved locations and 7 net booked Probable locations.
Sounding Lake Sparky MM Pool locations identified herein has 5 net
booked Proved locations and 4 net booked Probable locations.
Valhalla locations identified
herein has 25.1 net Doig, 5.0 net Charlie
Lake and 8.0 net Montney
booked Proved locations and 3.9 net Doig, 3.0 net Charlie Lake and 1.0 net Montney booked Probable locations.
Shaunavon locations identified
herein has 74.0 net booked Proved locations and 17.0 net booked
Probable locations. Greater Sawn locations identified herein has
58.4 net booked Proved locations and 21.1 net booked Probable
locations.
Production Rates
References to initial production ("IP") rates found in this
press release are useful for determining the presence of
hydrocarbons. There is no assurance as to the length of time that
wells will produce at such rates, and consideration must be given
to natural declines thereafter. As such, readers are
cautioned when using these production rates to aggregate Surge's
production.
Non-GAAP Financial Measures
Certain secondary financial measures in this press release –
namely, "adjusted funds flow", "adjusted funds flow per share",
"adjusted funds flow per boe", "net debt", "net operating
expenses", "operating netback" and "net debt to adjusted funds
flow" are not prescribed by GAAP. These non-GAAP financial measures
are included because management uses the information to analyze
business performance, cash flow generated from the business,
leverage and liquidity, resulting from the Company's principal
business activities and it may be useful to investors on the same
basis. None of these measures are used to enhance the Company's
reported financial performance or position. The non-GAAP measures
do not have a standardized meaning prescribed by IFRS and therefore
are unlikely to be comparable to similar measures presented by
other issuers. They are common in the reports of other companies
but may differ by definition and application. All non-GAAP
financial measures used in this document are defined below:
Adjusted Funds Flow & Adjusted Funds Flow per
Share
The Company adjusts cash flow from operating activities in
calculating adjusted funds flow for changes in non-cash working
capital, decommissioning expenditures, transaction and other costs,
and cash settled stock-based compensation plans, particularly cash
used to settle withholding obligations on stock-based compensation
arrangements that are settled in shares. Management believes the
timing of collection, payment or incurrence of these items involves
a high degree of discretion and as such may not be useful for
evaluating Surge's cash flows.
Changes in non-cash working capital are a result of the timing
of cash flows related to accounts receivable and accounts payable,
which management believes reduces comparability between periods.
Management views decommissioning expenditures predominately as a
discretionary allocation of capital, with flexibility to determine
the size and timing of decommissioning programs to achieve greater
capital efficiencies and as such, costs may vary between periods.
Transaction and other costs represent expenditures associated with
acquisitions, which management believes do not reflect the ongoing
cash flows of the business, and as such reduces comparability.
Subsequent to the third quarter of 2018, all of the Company's
stock-based compensation plans are equity classified as the Company
has the intention of settling all awards with shares. Cash settled
stock-based compensation currently represents the statutory tax
withholdings required on stock-based compensation awards and is a
discretionary allocation of capital. The Company has the option to
either require the holder to sell shares earned in the stock-based
compensation plan to satisfy tax withholdings, or the Company can
issue less shares to the individual and remit a cash payment to
satisfy tax withholding requirements. Each of these expenditures,
due to their nature, are not considered principal business
activities and vary between periods, which management believes
reduces comparability.
Adjusted funds flow per share is calculated using the same
weighted average basic and diluted shares used in calculating
income per share.
The following table reconciles cash flow from operating
activities to adjusted funds flow and adjusted funds flow per share
for the three and six months ended June 30,
2019 and 2018:
|
|
|
|
|
|
|
|
Three Months
Ended
|
Six Months
Ended
|
($000s except per
share)
|
Jun 30,
2019
|
|
Jun 30,
2018
|
Jun 30,
2019
|
|
Jun 30,
2018
|
Cash flow from
operating activities
|
$
|
45,807
|
|
$
|
33,725
|
$
|
74,715
|
|
$
|
57,940
|
Change in non-cash
working capital
|
|
3,126
|
|
|
2,897
|
|
14,168
|
|
|
3,395
|
Decommissioning
expenditures
|
|
1,111
|
|
|
832
|
|
2,818
|
|
|
3,580
|
Transaction and other
costs
|
|
698
|
|
|
60
|
|
892
|
|
|
768
|
Cash settled
stock-based compensation
|
|
-
|
|
|
1,082
|
|
-
|
|
|
1,082
|
Adjusted funds
flow
|
$
|
50,742
|
|
$
|
38,596
|
$
|
92,593
|
|
$
|
66,765
|
Per share –
basic
|
$
|
0.16
|
|
$
|
0.17
|
$
|
0.30
|
|
$
|
0.29
|
Net Debt
There is no comparable measure in accordance with IFRS for net
debt. Net debt is calculated as bank debt plus the liability
component of the convertible debentures plus or minus working
capital, however, excluding the fair value of financial contracts,
finance lease obligations and other long term liabilities. This
metric is used by management to analyze the level of debt in the
Company including the impact of working capital, which varies with
timing of settlement of these balances.
|
|
|
|
|
($000s)
|
As at June 30,
2019
|
|
As at December
31,
2018
|
As at June 30,
2018
|
Bank debt
|
$
(319,503)
|
|
$
(408,593)
|
$
(246,811)
|
Accounts
receivable
|
38,310
|
|
21,084
|
36,207
|
Prepaid expenses and
deposits
|
8,113
|
|
9,222
|
8,209
|
Accounts payable and
accrued liabilities
|
(47,771)
|
|
(42,350)
|
(34,496)
|
Convertible
debentures
|
(67,552)
|
|
(37,973)
|
(37,328)
|
Dividends
payable
|
(2,617)
|
|
(2,577)
|
(1,921)
|
Total
|
$
(391,020)
|
|
$
(461,187)
|
$
(276,140)
|
Net Operating Expenses
Net operating expenses are determined by deducting processing
and other revenue primarily generated by processing third party
volumes at processing facilities where the Company has an ownership
interest. It is common in the industry to earn third party
processing revenue on facilities where the entity has a working
interest in the infrastructure asset. Under IFRS this source of
funds is required to be reported as revenue. However, the Company's
principal business is not that of a midstream entity whose
activities are dedicated to earning processing and other
infrastructure payments. Where the Company has excess capacity at
one of its facilities, it will look to process third party volumes
as a means to reduce the cost of operating/owning the facility. As
such, third party processing revenue is netted against operating
costs in the MD&A.
Operating Netback & Adjusted Funds Flow per
boe
Operating netback & adjusted funds flow per boe for the
three and six months ended June 30,
2019 and 2018 are calculated on a per unit basis as
follows:
|
|
|
|
Three Months
Ended
|
Six Months
Ended
|
($000s except per
share)
|
Jun 30,
2019
|
|
Jun 30,
2018
|
Jun 30,
2019
|
|
Jun 30,
2018
|
Petroleum and natural
gas revenue*
|
$
|
107,665
|
|
$
|
87,094
|
$
|
205,533
|
|
$
|
155,384
|
Processing and other
income*
|
|
783
|
|
|
824
|
|
1,257
|
|
|
1,705
|
Royalties*
|
|
(13,788)
|
|
|
(12,982)
|
|
(24,849)
|
|
|
(21,922)
|
Operating
expenses*
|
|
(28,297)
|
|
|
(22,823)
|
|
(58,210)
|
|
|
(44,763)
|
Transportation
expenses*
|
|
(2,616)
|
|
|
(2,518)
|
|
(6,479)
|
|
|
(4,333)
|
Realized gain (loss)
on financial contracts*
|
|
(2,537)
|
|
|
(3,829)
|
|
(3,253)
|
|
|
(5,411)
|
Operating
netback
|
$
|
61,210
|
|
$
|
45,766
|
$
|
113,999
|
|
$
|
80,660
|
G&A
expense*
|
|
(3,652)
|
|
|
(3,200)
|
|
(7,122)
|
|
|
(6,401)
|
Interest
expense*
|
|
(6,816)
|
|
|
(3,970)
|
|
(14,284)
|
|
|
(7,494)
|
Adjusted funds
flow
|
$
|
50,742
|
|
$
|
38,596
|
$
|
92,593
|
|
$
|
66,765
|
Barrels of oil
equivalent (boe)
|
|
1,960,535
|
|
|
1,553,552
|
|
3,907,211
|
|
|
2,996,093
|
Operating netback
($ per boe)
|
$
|
31.24
|
|
$
|
29.46
|
$
|
29.17
|
|
$
|
26.91
|
Adjusted funds
flow ($ per boe)
|
$
|
25.90
|
|
$
|
24.84
|
$
|
23.69
|
|
$
|
22.27
|
* Taken directly from
the financial statements
|
|
|
|
|
|
|
|
|
|
|
Net Debt to Adjusted Funds Flow Ratio
Net debt to adjusted funds flow ratio is calculated as net debt
divided by annualized adjusted funds flow for the period. This
measure provides an indication of leverage and the number of years
it would take to repay the net debt based on the level of adjusted
funds flow.
Additional information relating to non-GAAP measures can be
found in the Company's most recent management's discussion and
analysis MD&A, which may be accessed through the SEDAR website
(www.sedar.com).
Neither the TSX nor its Regulation Services Provider (as that term is defined in the policies of the TSX) accepts responsibility for the adequacy or accuracy of this release.
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
This is a non-GAAP
financial measure which is defined in the Non-GAAP Financial
Measures section of this document.
|
2
|
As at August 8, 2019,
based on Reuters estimates.
|
3
|
As compared to the
2019 Capital Budget and Production Guidance press release dated
January 14, 2019. Net operating expense guidance was subsequently
revised in the first quarter 2019 press release dated May 6,
2019.
|
4
|
Capital efficiencies
is calculated as total exploration and development expenditures
during the period divided by current Production rates.
|
5
|
See Drilling
Locations in the Forward-Looking Statement section of this
document for further details.
|
6
|
See Reserves Data in
the Forward-Looking Statement section of this document for further
details.
|
7
|
Sproule has not
booked any waterflood reserves to this property in the YE2018
report.
|
8
|
Profit to investment
ratio (PIR) is calculated as the NPV from a project divided by the
capital investment required to realize such
cashflows.
|
9
|
Calculated as
unrestricted Credit Facility availability of $425 million, less
bank drawings of $319.5 million as at June 30, 2019.
|
10
|
Calculated as
total borrowing base of $500 million, less bank drawings of $319.5
million as at June 30, 2019.
|
11
|
Calculated as $0.10
annual dividend divided by $1.20 share price.
|
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SOURCE Surge Energy Inc.