Delphi Energy Corp. (“Delphi” or the
“Company”) (TSX:DEE) is pleased to announce
its financial and operational results, crude oil and natural gas
reserves information for the year ended December 31, 2017 and an
operations update.
2017 HIGHLIGHTS
- Produced 8,401 barrels of oil equivalent per day (“boe/d”), a
14 percent increase from 7,392 boe/d in 2016. Average
production in the fourth quarter of 2017 increased 35 percent to
9,588 boe/d compared to 7,127 boe/d in the fourth quarter of
2016;
- Field condensate production in the fourth quarter of 2017
increased to 2,374 barrels per day (“bbls/d”), a 77 percent
increase from 1,338 bbls/d in the fourth quarter of 2016;
- Field condensate and natural gas liquids (“NGL”) accounted for
58 percent of crude oil and natural gas revenues in 2017 and 64
percent in the fourth quarter;
- Realized a natural gas price of $4.04 per thousand cubic feet
(“mcf”) as a result of selling approximately 90 percent of our
natural gas in Chicago via full-path transportation arrangements on
Alliance and a hedging gain of $0.27 per mcf;
- Cash netbacks per barrel of oil equivalent (“boe”) increased by
eight percent resulting in adjusted funds flow of $36.7 million, a
23 percent increase over 2016. Cash netbacks per boe in the fourth
quarter of 2017 increased 29 percent resulting in adjusted funds
flow of $14.1 million, a 74 percent increase over the comparative
quarter of 2016.
- Drilled six (3.9 net) successful delineation wells and eleven
(7.1 net) successful in-fill wells in the Company’s Bigstone
Montney property, as part of a 17 (11.0 net) well drilling
program;
- Acquired 14.5 gross (13.5 net) sections of Montney rights in
the greater Bigstone area contiguous to the Company’s current
Montney lands;
- Invested $15.0 million in various infrastructure projects to
handle additional sales volumes and provide for reduced operating
expenses in 2018 and constructed over 21 kilometres of main
gathering and associated fuel gas pipelines and over five
kilometres of well tie-in and associated fuel gas pipelines;
- Increased total proved and total proved plus probable reserves
by 40 percent and 33 percent, respectively, from a successful
delineation drilling program in 2017;
- Increased the net present value (discounted at ten percent) of
total proved and total proved plus probable reserves by 23 percent
and 30 percent respectively;
- Increased field condensate reserves related to the Company’s
Montney shale gas reserves by 76 percent and 68 percent for total
proved and total proved plus probable reserves, respectively;
and
- For the 15 (9.6 net) wells brought on production in 2017,
achieved a proved developed producing finding and development cost
of $14.37 per boe(1).
(1) Includes capital to drill, complete, equip and tie-in of
$86.8 million and proved developed producing reserve “extensions
and improved recovery” of 6.04 million barrels of oil equivalent
(“mmboe”). Excludes technical revisions associated with other
wells. Includes $5.9 million of 2016 capital and excludes
$17.7 million of capital spent in 2017 for drilling and completion
of wells not brought on production in 2017.
FINANCIAL AND OPERATIONAL
HIGHLIGHTS |
|
|
|
|
|
|
Three months ended December 31 |
Twelve months ended December 31 |
|
2017 |
|
2016 |
|
% Change |
|
2017 |
|
2016 |
|
% Change |
|
Financial |
|
|
|
|
|
|
($ thousands, except
per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
revenues |
30,896 |
|
20,546 |
|
50 |
|
101,836 |
|
69,134 |
|
47 |
|
Net earnings
(loss) |
(1,764 |
) |
(25,461 |
) |
93 |
|
6,902 |
|
(41,114 |
) |
- |
|
Per share – basic and
diluted |
(0.01 |
) |
(0.16 |
) |
94 |
|
0.04 |
|
(0.26 |
) |
- |
|
Adjusted funds
flow(1) |
14,144 |
|
8,120 |
|
74 |
|
36,670 |
|
29,865 |
|
23 |
|
Per share
– basic and diluted(1) |
0.08 |
|
0.05 |
|
60 |
|
0.21 |
|
0.19 |
|
11 |
|
Net debt(1) |
136,421 |
|
85,945 |
|
59 |
|
136,421 |
|
85,945 |
|
59 |
|
Capital expenditures,
net of dispositions |
42,156 |
|
(30,679 |
) |
- |
|
117,292 |
|
(3,427 |
) |
- |
|
|
|
|
|
|
|
|
Weighted average shares
(000s) |
|
|
|
|
|
|
Basic |
185,472 |
|
155,630 |
|
19 |
|
173,171 |
|
155,540 |
|
11 |
|
Diluted |
185,472 |
|
155,630 |
|
19 |
|
173,975 |
|
155,540 |
|
12 |
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
(boe conversion – 6:1
basis) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
Field condensate
(bbls/d) |
2,374 |
|
1,338 |
|
77 |
|
1,968 |
|
1,444 |
|
36 |
|
Natural gas liquids
(bbls/d) |
1,315 |
|
1,125 |
|
17 |
|
1,250 |
|
1,183 |
|
6 |
|
Natural
gas (mcf/d) |
35,391 |
|
27,988 |
|
26 |
|
31,098 |
|
28,595 |
|
9 |
|
Total (Boe/d) |
9,588 |
|
7,127 |
|
35 |
|
8,401 |
|
7,392 |
|
14 |
|
|
|
|
|
|
|
|
Average realized sales
prices, before financial instruments |
|
|
|
|
|
|
Field condensate
($/bbl) |
64.20 |
|
57.17 |
|
12 |
|
59.14 |
|
48.64 |
|
22 |
|
Natural gas liquids
($/bbl) |
47.34 |
|
30.42 |
|
56 |
|
35.42 |
|
20.62 |
|
72 |
|
Natural gas
($/mcf) |
3.39 |
|
4.00 |
|
(15 |
) |
3.78 |
|
3.28 |
|
15 |
|
|
|
|
|
|
|
|
Netbacks ($/boe) |
|
|
|
|
|
|
Crude oil and natural
gas revenues |
35.03 |
|
31.33 |
|
12 |
|
33.22 |
|
25.55 |
|
30 |
|
Marketing income
(1) |
1.63 |
|
- |
|
- |
|
0.58 |
|
- |
|
- |
|
Realized
gain (loss) on financial instruments |
1.25 |
|
2.93 |
|
(57 |
) |
1.00 |
|
6.51 |
|
(85 |
) |
Revenue, after realized
financial instruments |
37.91 |
|
34.26 |
|
11 |
|
34.80 |
|
32.06 |
|
9 |
|
Royalties |
(2.26 |
) |
(1.89 |
) |
20 |
|
(2.35 |
) |
(2.49 |
) |
(6 |
) |
Operating expense |
(10.59 |
) |
(9.57 |
) |
11 |
|
(9.60 |
) |
(7.70 |
) |
25 |
|
Transportation
expense |
(4.62 |
) |
(4.93 |
) |
(6 |
) |
(5.67 |
) |
(5.63 |
) |
1 |
|
Operating netback (1) |
20.44 |
|
17.87 |
|
14 |
|
17.18 |
|
16.24 |
|
6 |
|
General and
administrative expenses |
(1.39 |
) |
(1.77 |
) |
(21 |
) |
(2.14 |
) |
(2.01 |
) |
6 |
|
Paid out restricted
share units |
- |
|
- |
|
- |
|
- |
|
(0.11 |
) |
100 |
|
Interest |
(3.02 |
) |
(3.72 |
) |
(19 |
) |
(3.08 |
) |
(3.09 |
) |
- |
|
Cash
netback (1) |
16.03 |
|
12.38 |
|
29 |
|
11.96 |
|
11.03 |
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Refer to non-GAAP measures
OPERATING AND FINANCIAL HIGHLIGHTS FOR THE QUARTER AND
YEAR ENDED DECEMBER 31, 2017
Delphi completed a $117.3 million capital
program for 2017. The program included $98.6 million for
drilling 17 (11.0 net) wells and completing 16 (10.2 net) wells,
along with $15.0 million for expansion of compression, pipeline
gathering and water disposal facilities and $2.2 million for the
acquisition of 13.5 net sections of land in the Bigstone area
. In addition, Delphi acquired a 17 million cubic feet per
day (“mmcf/d”) amine processing package to sweeten natural gas from
the Montney and allow it to be processed at a Company owned
facility rather than through third-party processers.
Commissioning of the amine facility is planned for the second
quarter of 2018. Capital spending in the fourth quarter net
of dispositions was $42.2 million and included the drilling of four
(2.6 net) wells and the completion of five (3.2 net) wells.
The drilling program in 2017 included six (3.9 net) delineation
wells, all of which were successful. The successful
delineation wells and investment in facilities have positioned the
Company for profitable growth.
Average production was 8,401 boe/d for the year
and 9,588 boe/d for the fourth quarter; increases of 14 and 35
percent over the corresponding periods in 2016. Field
condensate production in the fourth quarter was 2,374 bbls/d, an
increase of 77 percent over the same period in 2016. It
comprised 25 percent of production on a boe basis compared to 19
percent in the fourth quarter of 2016. While comprising 25
percent of production, field condensate generated 45 percent of
crude oil and natural gas revenues. Similarly, field
condensate and NGL production in the fourth quarter comprised 38
percent of total production and 64 percent of crude oil and natural
gas revenues.
Annual crude oil and natural gas revenues were
$101.8 million, an increase of 47 percent over 2016 due to both
increased production and higher realized prices. Crude oil
and natural gas revenues in the fourth quarter were $30.9 million,
an increase of 50 percent over the same period in 2016.
The operating netback was $17.18 per boe in the
year and $20.44 per boe in the fourth quarter while the
corresponding cash netbacks were $11.96 per boe and $16.03 per boe,
respectively. Annual adjusted funds flow increased 23 percent from
the prior year to $36.7 million or $0.21 per basic and diluted
share. Adjusted funds flow in the fourth quarter increased 74
percent to $14.1 million or $0.08 per basic and diluted share.
The borrowing base of Delphi’s senior credit
facility was increased by $15.0 million to $95.0 million in the
fourth quarter and a third bank joined the lending syndicate.
Bank debt at the end of the year was $26.9 million and outstanding
letters of credit were $7.3 million, leaving $60.8 million
available to be drawn. Net debt at the end of the year was $136.4
million resulting in a net debt to adjusted funds flow ratio of 2.4
times based on annualized fourth quarter adjusted funds flow of
$56.6 million.
NATURAL GAS MARKETING AND HEDGING
Given the high liquids content of Delphi’s
production, natural gas accounted for only 36 percent of crude oil
and natural gas revenues in the fourth quarter despite the fact
that Delphi realized a natural gas price before hedging gains of
$3.39 per mcf compared to an AECO price of $1.69 per mcf.
Over 90 percent of Delphi’s natural gas is sold
in the Chicago market via firm service on the Alliance pipeline
system. Approximately 60 percent of the expected Chicago
sales volumes in 2018 are hedged with NYMEX Henry Hub gas swaps for
an average of 19,826 million British thermal units per day
(“mmbtu/d”) at an average price of US$3.08 or C$3.85 per million
British thermal units (“mmbtu”), based on an exchange rate of 1.25
CAD per USD. Hedging gains added $0.47 per mcf to Delphi’s
realized natural gas price in the fourth quarter of 2017.
Delphi has a total of 57.3 mmcf/d of firm and
priority interruptible service on Alliance compared to total
average gas production of 35.4 mmcf/d in the fourth quarter of
2017. Delphi generates marketing income on excess service
through temporary assignment to other shippers at a premium over
cost or through the purchase of natural gas in Alberta or British
Columbia for sale in Chicago.
As a hedge to condensate and other natural gas
liquids prices that are correlated to WTI crude oil prices, Delphi
has an average of 2,238 bbls/d of WTI swaps in 2018 with an average
fixed price of C$71.60 per barrel.
RESERVES SUMMARY
GLJ Petroleum Consultants Ltd. (“GLJ”), the
Company’s independent petroleum engineering firm, has evaluated
Delphi’s crude oil, natural gas and natural gas liquids reserves as
at December 31, 2017 and prepared a reserves report (the “GLJ
Report”) in accordance with National Instrument 51-101 “Standards
of Disclosure for Oil and Gas Activities” and the “Canadian Oil and
Gas Evaluation Handbook”. GLJ’s price forecast dated January
1, 2018 was used in the evaluation. Company gross reserves in
the total proved and total proved plus probable categories
increased 40 percent and 33 percent respectively, compared to
2016.
The following is a summary of reserves information detailed in
the GLJ Report at December 31, 2017:
|
Conventional Natural Gas |
Shale Gas |
Natural Gas Liquids |
Oil Equivalent(1) |
|
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Reserves Category |
(mmcf) |
(mmcf) |
(mmcf) |
(mmcf) |
(mbbls) |
(mbbls) |
(mboe) |
(mboe) |
Proved |
|
|
|
|
|
|
|
|
Producing |
7,448 |
6,578 |
50,608 |
44,686 |
5,139 |
3,851 |
14,815 |
12,395 |
Developed
Non-Producing |
922 |
859 |
1,782 |
1,665 |
185 |
162 |
636 |
583 |
Undeveloped |
- |
- |
41,540 |
38,906 |
4,479 |
4,021 |
11,403 |
10,505 |
Total Proved |
8,370 |
7,437 |
93,931 |
85,257 |
9,803 |
8,034 |
26,853 |
23,483 |
Total
Probable |
6,784 |
6,099 |
76,377 |
68,515 |
7,772 |
6,172 |
21,633 |
18,608 |
Total
Proved Plus Probable |
15,154 |
13,536 |
170,307 |
153,771 |
17,576 |
14,206 |
48,486 |
42,091 |
|
|
|
|
|
|
|
|
|
(1) Oil equivalent amounts have been calculated
using a conversion rate of six thousand cubic feet of natural gas
to one barrel of oil (6:1).(2) Tables may not add due to
rounding.
Net Present Value of Future Net
Revenue
The estimated future net revenues associated
with Delphi’s reserves at December 31, 2017, based on the GLJ
January 1, 2018 price forecast, are summarized in the following
table. The net present value of future net revenues, discounted at
ten percent, from total proved and total proved plus probable
reserves increased by 23 percent and 30 percent respectively,
compared to 2016.
|
Net Present Values of Future Net Revenue |
Unit Value Before Income |
|
Before Income Taxes Discounted At (%/year)(1) |
Tax Discounted at |
|
|
|
|
|
|
10%/year(2) |
|
0% |
5% |
10% |
15% |
20% |
$/boe |
$/mcfe |
($
thousands) |
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
Producing |
195,971 |
161,745 |
138,322 |
121,706 |
109,423 |
11.16 |
1.86 |
Developed
Non-Producing |
11,431 |
9,352 |
7,906 |
6,867 |
6,094 |
13.56 |
2.26 |
Undeveloped |
145,793 |
85,602 |
49,797 |
27,239 |
12,279 |
4.74 |
0.79 |
Total Proved |
353,195 |
256,699 |
196,025 |
155,811 |
127,795 |
8.35 |
1.39 |
Total
Probable |
336,224 |
182,254 |
109,375 |
70,826 |
48,419 |
5.88 |
0.98 |
Total
Proved Plus Probable |
689,418 |
438,952 |
305,400 |
226,637 |
176,215 |
7.26 |
1.21 |
|
|
|
|
|
|
|
|
(1) Future net revenues are estimated using
forecast prices, costs arising from the anticipated development and
production of reserves, associated royalties, operating costs,
development costs, and abandonment and reclamation costs. The
estimated values disclosed do not necessarily represent fair market
value.(2) Unit values are calculated using net reserves defined as
Delphi’s working interest share after deduction of royalty
obligations plus Delphi’s royalty interests.(3) Tables may not add
due to rounding.
Future Development Costs
Future development costs (“FDC”) have increased
by $92.0 million and $113.0 million for the total proved and total
proved plus probable categories respectively, primarily as a result
of new undeveloped locations being booked offsetting the successful
delineation wells drilled in 2017.
The following table provides the future
development costs, undiscounted, included in the GLJ Report for
total proved and total proved plus probable reserves.
($
thousands) |
2018 |
2019 |
2020 |
2021 |
2022 |
Rem |
Total |
Total Proved |
73,580 |
55,162 |
21,417 |
138 |
- |
146 |
150,443 |
Total
Proved Plus Probable |
73,580 |
84,533 |
98,781 |
16,576 |
550 |
949 |
274,967 |
|
|
|
|
|
|
|
|
Forecast Prices
The following is a summary of GLJ’s January 1, 2018 price
forecast used in the evaluation.
|
Natural Gas |
Oil |
|
|
|
|
AECO/NIT |
NYMEX |
Edmonton |
NYMEX |
Pentanes Plus |
|
Exchange |
|
Spot |
Henry
Hub |
Light |
WTI |
Edmonton |
Inflation |
Rate |
Year |
$CDN/MMBtu |
$US/MMBtu |
$CDN/bbl |
$US/bbl |
$CDN/bbl |
% |
$US/$CDN |
2018 |
2.20 |
2.85 |
70.25 |
59.00 |
76.42 |
2.0 |
0.790 |
2019 |
2.54 |
3.00 |
70.25 |
59.00 |
74.68 |
2.0 |
0.790 |
2020 |
2.88 |
3.25 |
70.31 |
60.00 |
74.38 |
2.0 |
0.800 |
2021 |
3.24 |
3.50 |
72.84 |
63.00 |
77.16 |
2.0 |
0.810 |
2022 |
3.47 |
3.70 |
75.61 |
66.00 |
79.88 |
2.0 |
0.820 |
2023 |
3.58 |
3.86 |
78.31 |
69.00 |
82.53 |
2.0 |
0.830 |
2024 |
3.66 |
3.94 |
81.93 |
72.00 |
86.14 |
2.0 |
0.830 |
2025 |
3.73 |
4.02 |
85.54 |
75.00 |
89.76 |
2.0 |
0.830 |
2026 |
3.80 |
4.10 |
88.35 |
77.33 |
92.57 |
2.0 |
0.830 |
2027 |
3.88 |
4.18 |
90.22 |
78.88 |
94.43 |
2.0 |
0.830 |
2028+ |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
2.0 |
0.830 |
|
|
|
|
|
|
|
|
Reserves(1) Reconciliation
The following reconciliation of Delphi’s
reserves compares changes in the Company’s gross reserves at
December 31, 2016 to the reserves at December 31, 2017, each
evaluated in accordance with National Instrument 51-101
definitions. Negative technical revisions and economic
factors to the shale gas and associated natural gas liquids product
types were solely comprised of shale gas and the associated plant
extracted natural gas liquids. Technical revisions and
economic factors related to field condensate (included in the
“associated natural gas liquids” product type) were positive at 73
mboe and 54 mboe for total proved and total proved plus probable,
respectively.
|
Shale Gas |
Conventional Natural Gas |
|
|
Shale |
Associated Natural Gas |
Natural |
Associated Natural Gas |
Total Oil |
|
Gas |
Liquids |
Gas |
Liquids |
Equivalent |
Proved |
(mmcf) |
(mbbls) |
(mmcf) |
(mbbls) |
(mboe) |
December
31, 2016 |
67,316 |
|
6,189 |
|
9,357 |
|
245 |
|
19,213 |
|
Extensions and Improved
Recovery |
43,199 |
|
4,882 |
|
0 |
|
0 |
|
12,082 |
|
Technical
Revisions |
(6,854 |
) |
(370 |
) |
811 |
|
38 |
|
(1,339 |
) |
Discoveries |
- |
|
- |
|
- |
|
- |
|
- |
|
Acquisitions |
- |
|
- |
|
- |
|
- |
|
- |
|
Dispositions |
- |
|
- |
|
- |
|
- |
|
- |
|
Economic Factors |
(7 |
) |
(1 |
) |
(173 |
) |
(4 |
) |
(35 |
) |
Production |
(9,724 |
) |
(1,126 |
) |
(1,626 |
) |
(49 |
) |
(3,067 |
) |
December
31, 2017 |
93,931 |
|
9,574 |
|
8,370 |
|
230 |
|
26,853 |
|
|
|
|
|
|
|
|
Shale Gas |
Conventional Natural Gas |
|
|
Shale |
Associated Natural Gas |
Natural |
Associated Natural Gas |
Total Oil |
|
Gas |
Liquids |
Gas |
Liquids |
Equivalent |
Probable |
(mmcf) |
(mbbls) |
(mmcf) |
(mbbls) |
(mboe) |
December
31, 2016 |
62,193 |
|
5,500 |
|
6,934 |
|
218 |
|
17,239 |
|
Extensions and Improved
Recovery |
24,872 |
|
2,650 |
|
0 |
|
0 |
|
6,795 |
|
Technical
Revisions |
(10,584 |
) |
(605 |
) |
(3 |
) |
21 |
|
(2,349 |
) |
Discoveries |
- |
|
- |
|
- |
|
- |
|
- |
|
Acquisitions |
- |
|
- |
|
- |
|
- |
|
- |
|
Dispositions |
- |
|
- |
|
- |
|
- |
|
- |
|
Economic Factors |
(104 |
) |
(8 |
) |
(147 |
) |
(3 |
) |
(53 |
) |
Production |
- |
|
- |
|
- |
|
- |
|
- |
|
December
31, 2017 |
76,377 |
|
7,536 |
|
6,784 |
|
236 |
|
21,633 |
|
|
|
|
|
|
Shale Gas |
Conventional Natural Gas |
|
|
|
Associated |
|
Associated |
|
|
Shale |
Natural Gas |
Natural |
Natural Gas |
Total Oil |
|
Gas |
Liquids |
Gas |
Liquids |
Equivalent |
Proved
Plus Probable |
(mmcf) |
(mbbls) |
(mmcf) |
(mbbls) |
(mboe) |
December
31, 2016 |
129,509 |
|
11,689 |
|
16,292 |
|
464 |
|
36,452 |
|
Extensions and Improved
Recovery |
68,071 |
|
7,532 |
|
0 |
|
0 |
|
18,877 |
|
Technical
Revisions |
(17,438 |
) |
(976 |
) |
808 |
|
59 |
|
(3,689 |
) |
Discoveries |
- |
|
- |
|
- |
|
- |
|
- |
|
Acquisitions |
- |
|
- |
|
- |
|
- |
|
- |
|
Dispositions |
- |
|
- |
|
- |
|
- |
|
- |
|
Economic Factors |
(111 |
) |
(9 |
) |
(320 |
) |
(8 |
) |
(88 |
) |
Production |
(9,724 |
) |
(1,126 |
) |
(1,626 |
) |
(49 |
) |
(3,067 |
) |
December
31, 2017 |
170,307 |
|
17,110 |
|
15,154 |
|
466 |
|
48,486 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Gross reserves represent the operated and
non-operated working interest share of reserves before deduction of
royalties and does not include any royalty interests of the
Company. (2) Tables may not add due to rounding.
Finding and Development
Costs
In 2017, Delphi brought 15 gross (9.6 net) wells
on production. Capital to drill, complete, equip and tie-in
these wells totaled $86.8 million which includes $5.9 million of
capital spent on these wells in 2016 and excludes $17.7 million of
capital spent in 2017 for drilling and completion of wells not
brought on production in 2017. Company gross proved developed
producing reserve additions (classified as extensions and improved
recovery) for these wells was 6.04 mmboe resulting in a finding and
development cost of $14.37 per boe. Finding and development
costs for proved and proved plus probable reserves for 2017 and the
last three years are presented below.
Three year average finding, development and
acquisition costs in the total proved category is not meaningful as
total reserve additions are negative. Three year average
finding, development and acquisition costs in the total proved plus
probable category is not meaningful as total costs and reserve
additions are both negative. The Company disposed of both its
Wapiti and Hythe properties in 2015 and certain interests in
Bigstone through a transaction with an industry partner in
2016.
|
2017 |
|
2015 - 2017 Totals/Average |
|
Proved
Producing |
|
Total Proved |
|
Total Proved plus Probable |
|
Proved
Producing |
|
Total
Proved |
|
Total
Proved plus Probable |
|
Capital ($ thousands) |
|
|
|
|
|
|
Exploration
and Development ("E&D") Costs(1) |
108,829 |
|
108,829 |
|
108,829 |
|
196,630 |
|
196,630 |
|
196,630 |
|
Change in FDC related to E&D |
138 |
|
92,182 |
|
112,674 |
|
(3,967 |
) |
(15,218 |
) |
9,814 |
|
Total
E&D Costs |
108,967 |
|
201,011 |
|
221,503 |
|
192,663 |
|
181,412 |
|
206,444 |
|
|
|
|
|
|
|
|
Acquisition
and Disposition ("A&D") Costs(1) |
(1,595 |
) |
(1,595 |
) |
(1,595 |
) |
(92,892 |
) |
(92,892 |
) |
(92,892 |
) |
Change in FDC related to A&D |
- |
|
- |
|
- |
|
(2,483 |
) |
(65,807 |
) |
(126,267 |
) |
Total
A&D Costs |
(1,595 |
) |
(1,595 |
) |
(1,595 |
) |
(95,375 |
) |
(158,699 |
) |
(219,159 |
) |
|
|
|
|
|
|
|
Total
Costs |
107,372 |
|
199,416 |
|
219,908 |
|
97,288 |
|
22,713 |
|
(12,715 |
) |
|
|
|
|
|
|
|
Reserves (mboe) |
|
|
|
|
|
|
Total
Reserve Discoveries, Extensions & Revisions(2) |
4,673 |
|
10,707 |
|
15,101 |
|
12,188 |
|
7,692 |
|
9,365 |
|
Total Acquisitions and Dispositions |
- |
|
- |
|
- |
|
(6,846 |
) |
(14,513 |
) |
(25,976 |
) |
|
|
|
|
|
|
|
Total
Reserve Additions |
4,673 |
|
10,707 |
|
15,101 |
|
5,342 |
|
(6,821 |
) |
(16,612 |
) |
|
|
|
|
|
E&D,
including change in FDC related to E&D (F&D) |
23.32 |
|
18.77 |
|
14.67 |
|
15.81 |
|
23.58 |
|
22.04 |
|
E&D and A&D, including change in FDC
(F,D&A) |
22.98 |
|
18.62 |
|
14.56 |
|
18.21 |
|
(3.33 |
) |
0.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Capital invested has been reduced by $10.1
million for capital carry costs incurred in 2017 as part of the
transaction on the Bigstone Montney asset announced on November 8,
2016. (2) Includes extensions and improved recovery,
technical revisions, discoveries and economic factors.
Delphi will release its Annual Information Form
by April 2, 2018, which will include all required National
Instrument 51-101 reserves disclosure.
OPERATIONS UPDATE
The Company brought two (1.3 net) wells on
production in February 2018, the first wells to come on production
since November 2017. In one of these wells a new ball drop
frac liner was successfully tested in a portion of the horizontal
lateral. This new frac system will accommodate more frac
stages and higher frac pump rates as well as simplifying wellbore
clean-out operations, if needed.
Delphi has completed its planned winter drilling
program with four gross (2.6 net) wells having been drilled prior
to March. Completion operations have commenced on the first
well at 16-10-60-24W5 (“16-10”). 16-10 was drilled to a total
depth of 5,994 metres and is the western-most well the Company has
drilled in over six years. The well will be completed through
a 65-stage hybrid frac design as part of the Company’s sixth
generation frac design utilizing 30 percent more discrete stages
and 30 percent more sand than used previously. The frac crew
will remain in the field with plans to complete the remaining three
2018 wells as weather permits.
All major equipment for the Company’s amine
sweetening plant is on location and plans remain on-track for the
construction and commissioning of the project at the 7-11-60-23W5
compression and dehydration Montney facility. When brought
on-line in the second quarter of 2018, up to 17 mmcf/d of gross raw
sweetened Montney gas will be processed at the Repsol operated
Bigstone Gas Plant where the Company owns a 25% working
interest. This will significantly reduce operating costs for
the portion of Montney gas that gets processed at this plant.
Delphi continues to explore other initiatives to
reduce the cost structure of its Bigstone Montney operation.
Pipeline infrastructure for field condensate and water handling are
top priorities as these have the potential to significantly reduce
associated operating costs and reduce or eliminate reliance on
trucking.
OUTLOOK AND 2018 GUIDANCE
Delphi has maintained a high level of drilling
activity over the past 15 months with 21 new wells drilled,
increasing the total number of wells drilled on its 169 sections of
Montney acreage to 52 over the past 5 years. This increased pace of
capitalization has materially de-risked the overall acreage with
several successful delineation wells to the south and west portions
of its acreage.
Although expectations are well defined on the
eastern portions of the lands, increased delineation drilling to
the west will be beneficial in defining a “richer” condensate type
curve expectation. Nine wells have now been drilled on the west
side with greater than 90 days of production where the Company
continues to enhance its completion techniques from the observed
production results.
The Company views this initial success moving
west to acreage that is yielding 200 to 300 bbls/mmcf of field
condensate as very positive with an expectation of increased margin
growth and enhanced return on capital.
With the two most recent wells on-stream,
Delphi’s production over the last 7 days has averaged approximately
10,800 boe/d (27 percent condensate and 15 percent NGL’s) based on
field estimates. The Company also has five new wells in
various stages of completion operations with expectations for all
wells to commence production by early third quarter. This
puts the Company in an excellent position to pause its drilling
program through spring breakup to evaluate the production
performance of the new wells to best plan the second half of the
2018 capital program. As such the Company is providing
guidance for the first half of 2018 only at this time, giving full
consideration to the scheduled production downtime associated with
ongoing completion operations and the construction and
commissioning of the amine processing facility. Delphi looks to
formalize its second half 2018 capital program later in the second
quarter.
The following table highlights the major
assumptions with respect to Delphi’s guidance for the first half of
2018.
|
2018 First Half Guidance |
Net
Capital Program ($ million) |
$38 - $45 |
Gross
Well Count Drilled (net) |
4 (2.6) |
Gross
Well Count On Production (net) |
5 (3.3) – 7 (4.6) |
|
|
|
2018 First Half Guidance |
2017 First Half Actuals |
% Change |
Average
Production (boe/d) |
9,800 – 10,200 |
7,336 |
36 |
Natural Gas
(mmcf/d) |
35.0 –
37.0 |
26.6 |
35 |
Field Condensate (bbls/d) |
2,350 – 2,450 |
1,738 |
38 |
NGL’s (bbls/d) |
1,470 –
1,530 |
1,160 |
29 |
Percent Liquids (%) |
40 |
40 |
- |
Adjusted Funds Flow
(“AFF”) |
$25.0 -
$27.0 |
$15.2 |
71 |
Cash Netback (per boe, excluding hedges) |
$14.25 |
$11.43 |
25 |
Net Debt (1) (2) |
$149.0
– $154.0 |
$97.8 |
55 |
Net Debt / AFF (annualized) |
2.9 – 3.0 |
3.2 |
|
|
|
|
|
(1) Based on WTI crude oil price of $63 per barrel, NYMEX Henry
Hub natural gas price of $2.80 per mmbtu and FX of 1.27 CAD per
USD. (2) Net debt is defined as the sum of bank debt, senior
secured notes and the long term portion of unutilized take-or-pay
contract plus (minus) the working capital deficit (surplus)
excluding the current portion of the fair value of the financial
instruments.
Delphi remains well positioned with a high
quality resource base supported by strategic infrastructure and a
large drilling inventory, a strategic “long Alliance Chicago”
natural gas marketing strategy, and a strong commodity hedge
position.
CONFERENCE CALL AND WEBCAST
A conference call and webcast to review 2017
year end results is scheduled for 9:00 a.m. Mountain Time (11:00
a.m. Eastern Time) on Thursday, March 8, 2018. The conference
call number is 1-844-358-8760. A brief presentation by David J.
Reid, President and CEO, Mark Behrman, CFO and Rod Hume, Senior
Vice President, Engineering will be followed by a question and
answer period. The conference call will also be broadcast
live on the Internet and may be accessed through
www.delphienergy.ca or by entering
https://edge.media-server.com/m6/p/fitkqvdz in your web
browser.
A recorded rebroadcast will be archived and made
available on the Company’s website at www.delphienergy.ca or by
entering https://edge.media-server.com/m6/p/fitkqvdz in your web
browser. Delphi's annual and fourth quarter 2017 financial
statements and management’s discussion and analysis are available
on the Company’s website at www.delphienergy.ca and SEDAR at
www.SEDAR.com.
About Delphi Energy Corp.
Delphi Energy Corp. is an industry-leading
producer of liquids-rich natural gas. The Company has
achieved top decile results through the development of our high
quality Montney property, uniquely positioned in the Deep Basin of
Bigstone, in northwest Alberta. Delphi continues to outperform key
industry players by improving operational efficiencies and growing
our dominant Bigstone land position in this world-class play.
Delphi is headquartered in Calgary, Alberta and trades on the
Toronto Stock Exchange under the symbol DEE.
FOR FURTHER INFORMATION PLEASE
CONTACT:
DELPHI ENERGY CORP.2300 - 333 –
7th Avenue S.W.Calgary, AlbertaT2P 2Z1Telephone: (403)
265-6171 Facsimile: (403) 265-6207Email:
info@delphienergy.ca Website:
www.delphienergy.ca
|
DAVID J. REIDPresident & CEO |
|
MARK D. BEHRMANCFO |
|
|
|
|
Forward-Looking
Statements. This news release contains
forward-looking statements and forward-looking information within
the meaning of applicable Canadian securities laws. These
statements relate to future events or the Company’s future
performance and are based upon the Company’s internal assumptions
and expectations. All statements other than statements of
present or historical fact are forward-looking statements.
Forward-looking statements are often, but not always, identified by
the use of any of the words “expect”, “anticipate”, “continue”,
“estimate”, “may”, “will”, “should”, “believe”, "intends”,
“forecast”, “plans”, “guidance”, “budget” and similar
expressions.
More particularly and without limitation, this
release contains forward-looking statements and information
relating to petroleum and natural gas production estimates and
weighting, projected crude oil and natural gas prices, future
exchange rates, expectations as to royalty rates, expectations as
to transportation and operating costs, expectations as to general
and administrative costs and interest expense, expectations as to
capital expenditures and net debt, planned capital spending, future
liquidity and Delphi’s ability to fund ongoing capital requirements
through operating cash flows and its credit facilities, supply and
demand fundamentals for oil and gas commodities, timing and success
of development and exploitation activities, cash availability for
the financing of capital expenditures, access to third-party
infrastructure, treatment under governmental regulatory regimes and
tax laws and future environmental regulations.
Furthermore, statements relating to “reserves”
are deemed to be forward-looking statements as they involve the
implied assessment, based on certain estimates and assumptions that
the reserves described can be profitable in the future.
The forward-looking statements and information
contained in this release are based on certain key expectations and
assumptions made by Delphi. The following are certain
material assumptions on which the forward-looking statements and
information contained in this release are based: the stability of
the global and national economic environment, the stability of and
commercial acceptability of tax, royalty and regulatory regimes
applicable to Delphi, exploitation and development activities being
consistent with management’s expectations, production levels of
Delphi being consistent with management’s expectations, the absence
of significant project delays, the stability of oil and gas prices,
the absence of significant fluctuations in foreign exchange rates
and interest rates, the stability of costs of oil and gas
development and production in Western Canada, including operating
costs, the timing and size of development plans and capital
expenditures, availability of third party infrastructure for
transportation, processing or marketing of oil and natural gas
volumes, prices and availability of oilfield services and equipment
being consistent with management’s expectations, the availability
of, and competition for, among other things, pipeline capacity,
skilled personnel and drilling and related services and equipment,
results of development and exploitation activities that are
consistent with management’s expectations, weather affecting
Delphi’s ability to develop and produce as expected, contracted
parties providing goods and services on the agreed timeframes,
Delphi’s ability to manage environmental risks and hazards and the
cost of complying with environmental regulations, the accuracy of
operating cost estimates, the accurate estimation of oil and gas
reserves, future exploitation, development and production results
and Delphi’s ability to market oil and natural gas successfully to
current and new customers. Additionally, estimates as to expected
average annual production rates assume that no unexpected outages
occur in the infrastructure that the Company relies on to produce
its wells, that existing wells continue to meet production
expectations and any future wells scheduled to come on in the
coming year meet timing and production expectations.
Commodity prices used in the determination of
forecast revenues are based upon general economic conditions,
commodity supply and demand forecasts and publicly available price
forecasts. The Company continually monitors its forecast
assumptions to ensure the stakeholders are informed of material
variances from previously communicated expectations.
Financial outlook information contained in this
release about prospective results of operations, financial position
or cash flows is based on assumptions about future events,
including economic conditions and proposed courses of action, based
on management’s assessment of the relevant information currently
available. Readers are cautioned that such financial outlook
information contained in this release should not be used for
purposes other than for which it is disclosed.
Although the Company believes that the
expectations reflected in such forward-looking statements and
information are reasonable, it can give no assurance that such
expectations will prove to be correct and such forward-looking
statements should not be unduly relied upon. Since forward-looking
statements and information address future events and conditions, by
their very nature they involve inherent known and unknown risks and
uncertainties. Delphi’s actual results, performance or
achievements could differ materially from those expressed in, or
implied by, these forward-looking statements and, accordingly, no
assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of
them do so, what benefits Delphi will derive therefrom. Should one
or more of these risks or uncertainties materialize, or should
assumptions underlying forward-looking statements prove incorrect,
actual results may vary materially from those currently anticipated
due to a number of factors and risks. These include, but are
not limited to, the risks associated with the oil and gas industry
in general such as 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 estimates and projections relating to production
rates, costs and expenses, commodity price and exchange rate
fluctuations, marketing and transportation, environmental risks,
competition from others for scarce resources, the ability to access
sufficient capital from internal and external sources, changes in
governmental regulation of the oil and gas industry and changes in
tax, royalty and environmental legislation. Additional
information on these and other factors that could affect the
Company’s operations or financial results are included in the
Company’s most recent Annual Information Form and other reports on
file with the applicable securities regulatory authorities and may
be accessed through the SEDAR website (www.sedar.com).
Readers are cautioned that the foregoing list of
factors is not exhaustive. Furthermore, the forward-looking
statements contained in this release are made as of the date of
this release for the purpose of providing the readers with the
Company’s expectations for the coming year. The
forward-looking statements and information may not be appropriate
for other purposes. Delphi 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. The
forward-looking statements contained in this release are expressly
qualified in their entirety by this cautionary statement.
Basis of Presentation.
For the purpose of reporting production
information, reserves and calculating unit prices and costs,
natural gas volumes have been converted to a barrel of oil
equivalent (boe) using six thousand cubic feet equal to one
barrel. A boe conversion ratio of 6:1 is based upon an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the
wellhead. This conversion conforms to the Canadian Securities
Administrators’ National Instrument 51-101 when boes are
disclosed. Boes may be misleading, particularly if used in
isolation.
As per CSA Staff Notice 51-327 initial test
results and initial production performance should be considered
preliminary data and such data is not necessarily indicative of
long-term performance or of ultimate recovery. “IP” is an
abbreviation for “Initial Production” and represents average
production rates over the indicated time period in producing
days.
Non-GAAP Measures. The
release contains the terms “adjusted funds flow”, “adjusted funds
flow per share”, “net debt”, “net debt to adjusted funds flow
ratio”, “marketing income”, “operating netbacks”, “cash netbacks,”
and “netbacks” which are not recognized measures under GAAP.
The Company uses these measures to help evaluate its
performance. Management considers netbacks an important
measure as it demonstrates its profitability relative to current
commodity prices and costs of production. Management uses adjusted
funds flow to analyze performance and considers it a key measure as
it demonstrates the Company’s ability to generate the cash
necessary to fund future capital investments, abandonment
obligations and to repay debt. Adjusted funds flow is a non-GAAP
measure and has been defined by the Company as cash flow from
operating activities before decommissioning expenditures and
changes in non-cash working capital from operating activities. The
Company also presents adjusted funds flow per share whereby amounts
per share are calculated using weighted average shares outstanding
consistent with the calculation of earnings per share. Delphi’s
determination of adjusted funds flow may not be comparable to that
reported by other companies nor should it be viewed as an
alternative to cash flow from operating activities, net earnings or
other measures of financial performance calculated in accordance
with GAAP. The Company has defined net debt as the sum of
bank debt, senior secured notes and the long term portion of
unutilized take-or-pay contract plus/minus working capital
deficit/surplus excluding the current portion of the fair value of
financial instruments. Net debt is used by management to monitor
remaining availability under its credit facilities. Marketing
income is defined as the margin earned on the sale of purchased
third party natural gas volumes and premiums received on the
assignment of a portion of committed capacity on the Alliance
pipeline system to a third party. Management considers
marketing income important measures of the Company’s ability to
mitigate the cost of excess committed capacity. Operating netbacks
have been defined as revenue plus marketing income less royalties,
transportation and operating costs. Cash netbacks have been
defined as operating netbacks less interest on bank debt and senior
secured notes, general and administrative costs and cash costs
related to the Company’s restricted share units. Netbacks are
generally discussed and presented on a per boe basis.