- Production of 24,355 Boe per day for the
quarter, up 105% year over year -- Fourteen new wells on line since
April 1 - - Initial production rates in Bronco in line with legacy
wells - - Negotiating a definitive agreement to sell Aneth Field
-
Resolute Energy Corporation (“Resolute” or the “Company”)
(NYSE:REN) today reported financial and operating results for the
quarter and six months ended June 30, 2017.
Rick Betz, Resolute’s Chief Executive Officer, said: “Resolute
has continued to ramp up production, driven by our successful
drilling in the Delaware Basin. Second quarter production
averaged 24,355 barrels of oil equivalent (“Boe”) per day (63% oil
and 78% liquids), an increase of 12,490 Boe per day, or 105
percent, from the prior year second quarter. On a sequential basis,
second quarter production increased by 4,653 Boe per day, or 24
percent compared to first quarter volumes of 19,702 Boe per
day. Sequential production from our Permian Basin operations
increased by 33 percent, from 13,798 Boe per day in the first
quarter to 18,383 Boe per day in the second quarter and increased
227 percent from the prior year second quarter. These second
quarter volumes include approximately 630 Boe per day from our
newly acquired Bronco acreage.
“Our production growth continued to accelerate through the end
of the second quarter and into the third quarter, with estimated
July production of approximately 29,500 Boe per day. Our Permian
Basin production increased to 23,600 Boe per day during the month
with the Bronco area contributing approximately 3,400 Boe per day.
For the second quarter Aneth production was approximately 6,000 Boe
per day, and once again essentially flat to the first quarter and
the prior year despite continued restraint in capital spending.
“Net income for the second quarter was $13.2 million up from
$1.5 million in the first quarter. Adjusted EBITDA (a non-GAAP
measure) increased twelve percent to $32.4 million compared to
$28.9 million in the first quarter. This increase in Adjusted
EBITDA was achieved not just by increased production but also by
continued improvement in lease operating expenses (“LOE”) more than
offsetting weakness in commodity prices. For the quarter, we
saw LOE in our Delaware Basin operations decline to $4.87 per Boe
produced from $5.42 per Boe in the first quarter. Cash general and
administrative expenses (a non-GAAP measure) for the quarter also
showed significant improvement, declining from $4.28 per Boe in the
first quarter to $2.95 per Boe in the second quarter.
“During the second quarter we spud seven wells and completed ten
wells. We completed four mid-length laterals in Mustang with 24
hour peak IP rates averaging 2,584 Boe per day, two long laterals
in Appaloosa with average initial 24 hour peak IP rates of 3,657
Boe per day and four drilled but uncompleted (“DUCs”) wells
acquired in the Bronco transaction. At quarter-end we had four
wells waiting on completion and three wells in various stages of
drilling. Also during the quarter, we continued to de-risk our
drilling inventory by completing two Wolfcamp B wells, one a
mid-length lateral in central Mustang and one a mid-length lateral
in Bronco. We are continuing to study early-time production
from these wells. As expected they look much stronger than earlier
generation B wells.
“Year to date, we have reached total depth on sixteen wells.
These include nine mid-length laterals and seven long laterals. We
have completed and brought on line eighteen wells since January,
including eleven mid-length laterals, four long laterals and three
standard length laterals. Based on our current drilling schedule,
we expect to spud the last well in our originally announced 22 well
drilling plan early in the fourth quarter. While we do not
believe it would be prudent at this time to add a third rig to our
program, our advanced drilling pace does give us the opportunity to
expand the program with our existing rigs. Were we to keep both
rigs running through year end it would result in up to five
additional spuds in 2017. We will be evaluating this option over
the coming months.
“Putting more focus on activities in Bronco, we closed the
acquisition in May and immediately commenced completion operations
on the six operated DUCs included in the transaction. To date
we have completed five of the wells including three Wolfcamp A
wells and two Wolfcamp B wells. Two of the wells were mid-length
laterals that were completed with 32 frac stages and had initial
production in the first week of June. The 24 hour peak IP
rates on these two wells were 3,013 and 2,764 Boe per day, with
currently calculated 30-day rates of 2,541 and 2,402 Boe per day,
respectively. These rates compare favorably with our Mustang
and Appaloosa results. The remaining four wells were standard
length laterals. Two of the wells were completed with 19 frac
stages and came on line at the end of June. We are encouraged
by the 24 hour peak IP rates from these wells, averaging 2,300 Boe
per day. Of the last two wells, one well has been completed
and is flowing back and the second well is waiting on
completion. We expect the seventh DUC acquired, an
outside-operated well, to be completed in September.
“In addition to the drilling and completion activity, we made
important progress on our field infrastructure. In June we
began shifting the gathering of our oil production from trucks into
an oil pipeline constructed by our mid-stream partner. By the
end of July, substantially all Mustang and Appaloosa oil volumes
were being gathered by pipeline. This greatly simplifies the
marketing of our production, it reduces our effective
transportation costs, it entails less traffic impact on our
in-field roads and other infrastructure, and it is expected to be
more environmentally friendly than trucking the product to market.
At this time, Bronco oil volumes continue to be gathered by truck,
but we expect to move those volumes to pipe later this year.
Also in Bronco we completed the build out of production facilities
which will support the long-term development of this
asset.
“During the second quarter we did experience a limited number of
instances of well interference, primarily in Appaloosa, as we
completed infill wells in close proximity to older producing wells
in the same horizon. We did not observe this same impact when
drilling well pairs in Mustang. We estimate these events reduced
company production for the quarter by approximately 1,000 to 1,200
Boe per day, or approximately four to five percent. These types of
events are not atypical for development in the Permian Basin and
have been reported by other operators as well.
“We have made operational adjustments based on our own
observations and our review of recent industry best practices,
which we believe will reduce these impacts in the future.
First, we anticipate that our future drilling will be done in
groups of two to four wells followed by sequential frac operations
on all of the wells in the group. We made this change starting with
our two Ranger long laterals in Appaloosa in June. These
wells are currently waiting on completion. That rig has moved
and is currently drilling the first of two long lateral South
Elephant wells which will be drilled together and then completed
sequentially. Importantly, the initial well on this pad is
our first Wolfcamp C well. This well will help de-risk our Delaware
Basin drilling inventory, satisfy depth clauses on certain leases
and give us valuable data as we design future pad drilling
operations. We expect these wells will be completed starting in
October. In Mustang we have one well to finish drilling
before we shift to two well pads through the remainder of the
year. We believe this shift to pad drilling will result in
savings of between $0.5 and $1.0 million dollars per pad.
“Second, we have moved to increase the density of perf clusters
in our frac design. We do not expect this to change our
overall proppant loading or completion costs. The goal of
this revised design is to give us a more effective completion in
the near wellbore environment while reducing the instances where
individual fractures reach out long distances and negatively affect
adjacent wells.
“The shift to pad drilling is expected to modestly impact
production growth in the second half of the year as a small number
of completions are delayed. Including our Bronco completion
program, we remain comfortable with our previously announced
guidance of 24,000 to 28,000 Boe per day, prior to any adjustment
that may be required as a result of closing on the proposed Aneth
divestiture. At the mid-point this would represent an increase of
more than 83 percent over 2016 production levels. Additionally, we
have experienced a modest shift in our oil percentage resulting
from our mix of producing wells. Looking at our legacy assets we
remain comfortable with our percentage oil guidance. However, as we
bring additional Bronco wells on line we have observed gas to oil
ratios consistent with Mustang, which has increased our blended gas
to oil ratio marginally. Including anticipated production from
Bronco, the Company’s percentage oil may decline by one to two
percent. From a capital expenditure standpoint, when we
include approximately $37 million in net capital allocated to
Bronco and approximately $15 million in increased capital
associated with increased working interests in certain second
quarter wells and unbudgeted outside-operated wells, we are
increasing our capital guidance range to $270 million to $285
million.
“As you know, we are actively pursuing the disposition of our
Aneth Field assets. We recently completed a thorough
marketing process that resulted in multiple acceptable bids.
We are currently in negotiations on definitive documentation with
our preferred counterparty. We expect to announce a signing
of such documents during the third quarter with the objective of
closing the transaction in the fourth quarter. Upon a closing we
anticipate reissuing production and cost guidance. In the
meantime, recall that we solidified our liquidity position with a
$125 million add-on to our existing Senior Note due 2020, insuring
that we were well positioned to close the Bronco acquisition as
well as execute the drilling program.
“Finally, as we announced on August 2, Resolute’s Board of
Directors has added two new members, Janet Pasque and Tod
Benton. Ms. Pasque and Mr. Benton bring a wealth of relevant
experience to our board, an unwavering commitment to excellence and
integrity, and a thoughtful approach to the industry and the
Company. As a result, the board now consists of nine members,
six of whom are independent. We welcome Janet and Tod, and
are excited about their future contribution to the success of
Resolute.”
Operations Update
Following is an update of certain operating activities since
April 1:
Drilling Activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Length |
|
|
|
|
|
|
Spud to TD |
Well Name |
|
Area1 |
|
Zone2 |
|
(feet) |
|
|
Status |
|
TD date |
|
(days) |
Iron City State
L05H |
|
M |
|
LWCA |
|
|
7,717 |
|
|
Producing |
|
4/25/2017 |
|
21 |
Steamworks 0304H |
|
M |
|
UWCA |
|
|
7,489 |
|
|
Producing |
|
5/21/2017 |
|
19 |
North Goat 2 Unit
B101SL |
|
A |
|
WCB |
|
|
10,218 |
|
|
Completing |
|
5/26/2017 |
|
19 |
Breckenridge L06H |
|
M |
|
LWCA |
|
|
7,825 |
|
|
Producing |
|
6/13/2017 |
|
16 |
Ranger B106H |
|
A |
|
WCB |
|
|
9,786 |
|
|
Completing |
|
7/17/2017 |
|
23 |
Ranger L07H |
|
A |
|
LWCA |
|
|
9,681 |
|
|
WOC |
|
7/2/2017 |
|
19 |
Uinta L04HR |
|
M |
|
LWCA |
|
|
7,620 |
|
|
Flowing back |
|
7/11/2017 |
|
15 |
Ace L06H |
|
M |
|
LWCA |
|
|
7,894 |
|
|
WOC |
|
8/3/2017 |
|
15 |
South Elephant
C207SL |
|
A |
|
WCC |
|
|
9,465 |
|
|
Drilling |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1. Area
abbreviation legend: M – Mustang and A – Appaloosa and B –
Bronco |
2. Zone
abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp
A; WCB –Wolfcamp B; WCC –Wolfcamp C |
|
Completion Activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Length |
|
|
First |
|
Frac |
|
Proppant per |
|
Well Name |
|
Area1 |
|
Zone2 |
|
(feet) |
|
|
sales |
|
stages |
|
foot (lbs) |
|
Pipeworks B05H |
|
M |
|
WCB |
|
|
7,377 |
|
|
5/7/2017 |
|
29 |
|
|
1,818 |
|
Pipeworks L06H |
|
M |
|
LWCA |
|
|
7,382 |
|
|
5/7/2017 |
|
29 |
|
|
1,797 |
|
South Goat 2 Unit
U01H |
|
A |
|
UWCA |
|
|
10,097 |
|
|
4/17/2017 |
|
37 |
|
|
1,772 |
|
North Elephant 2 Unit
U06H |
|
A |
|
UWCA |
|
|
9,571 |
|
|
5/27/2017 |
|
40 |
|
|
2,012 |
|
Iron City State
L05H |
|
M |
|
LWCA |
|
|
7,605 |
|
|
6/9/2017 |
|
33 |
|
|
2,008 |
|
Steamworks 0304H |
|
M |
|
UWCA |
|
|
7,375 |
|
|
6/12/2017 |
|
32 |
|
|
2,065 |
|
Breckenridge L06H |
|
M |
|
LWCA |
|
|
7,720 |
|
|
7/8/2017 |
|
29 |
|
|
1,803 |
|
Uinta L04HR |
|
M |
|
LWCA |
|
|
7,510 |
|
|
Flowing back |
|
27 |
|
|
1,796 |
|
Brigham Fuente
4402HL |
|
B |
|
LWCA |
|
|
7,200 |
|
|
6/3/2017 |
|
32 |
|
|
2,013 |
|
Brigham Fuente
4401HU |
|
B |
|
WCB |
|
|
7,025 |
|
|
6/3/2017 |
|
32 |
|
|
2,022 |
|
Durham Smith Fuente
207HL |
|
B |
|
WCB |
|
|
4,541 |
|
|
WOC |
|
- |
|
- |
|
Durham Smith Fuente
209HL |
|
B |
|
WCB |
|
|
4,663 |
|
|
Flowing back |
|
22 |
|
|
2,022 |
|
Durham Smith Fuente
212HU |
|
B |
|
UWCA |
|
|
4,700 |
|
|
6/25/2017 |
|
19 |
|
|
1,992 |
|
Durham Smith Fuente
214HU |
|
B |
|
UWCA |
|
|
4,616 |
|
|
6/25/2017 |
|
19 |
|
|
1,998 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1. Area
abbreviation legend: M – Mustang and A – Appaloosa and B –
Bronco |
2. Zone
abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp
A; WCB –Wolfcamp B |
|
Production Activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Peak rate |
|
|
Peak rate |
|
|
Peak rate |
|
|
|
|
|
|
|
Length |
|
|
24 hour |
|
|
30 day |
|
|
60 day |
|
Well Name |
|
Area1 |
|
Zone2 |
|
(feet) |
|
|
Boe per day |
|
|
Boe per day |
|
|
Boe per day |
|
South Elephant
U04H |
|
A |
|
UWCA |
|
|
8,902 |
|
|
|
2,716 |
|
|
|
2,351 |
|
|
|
2,198 |
|
Pipeworks B05H |
|
M |
|
WCB |
|
|
7,377 |
|
|
|
2,727 |
|
|
|
2,393 |
|
|
|
2,112 |
|
Pipeworks L06H |
|
M |
|
LWCA |
|
|
7,382 |
|
|
|
2,653 |
|
|
|
2,294 |
|
|
|
2,024 |
|
South Goat 2 Unit
U01H |
|
A |
|
UWCA |
|
|
10,097 |
|
|
|
3,766 |
|
|
|
3,517 |
|
|
|
3,180 |
|
North Elephant 2 Unit
U06H |
|
A |
|
UWCA |
|
|
9,571 |
|
|
|
3,549 |
|
|
|
3,129 |
|
|
|
2,534 |
|
Iron City State
L05H |
|
M |
|
LWCA |
|
|
7,605 |
|
|
|
2,827 |
|
|
|
2,563 |
|
|
- |
|
Steamworks 0304H |
|
M |
|
UWCA |
|
|
7,375 |
|
|
|
2,129 |
|
|
|
1,954 |
|
|
- |
|
Breckenridge L06H |
|
M |
|
LWCA |
|
|
7,720 |
|
|
|
2,728 |
|
|
- |
|
|
- |
|
Uinta L04HR |
|
M |
|
LWCA |
|
|
7,510 |
|
|
- |
|
|
- |
|
|
- |
|
Durham Smith Fuente
201HL3 |
|
B |
|
WCB |
|
|
4,507 |
|
|
|
1,642 |
|
|
|
1,543 |
|
|
|
1,413 |
|
Durham Smith Fuente
204HU3 |
|
B |
|
UWCA |
|
|
4,506 |
|
|
|
1,788 |
|
|
|
1,584 |
|
|
|
1,512 |
|
Brigham Fuente
4402HL |
|
B |
|
LWCA |
|
|
7,200 |
|
|
|
3,013 |
|
|
|
2,541 |
|
|
- |
|
Brigham Fuente
4401HU |
|
B |
|
WCB |
|
|
7,025 |
|
|
|
2,764 |
|
|
|
2,402 |
|
|
- |
|
Durham Smith Fuente
209HL |
|
B |
|
WCB |
|
|
4,663 |
|
|
- |
|
|
- |
|
|
- |
|
Durham Smith Fuente
212HU |
|
B |
|
UWCA |
|
|
4,700 |
|
|
|
2,029 |
|
|
|
1,343 |
|
|
- |
|
Durham Smith Fuente
214HU |
|
B |
|
UWCA |
|
|
4,616 |
|
|
|
2,551 |
|
|
|
1,866 |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1. Area
abbreviation legend: M – Mustang and A – Appaloosa and B –
Bronco |
2. Zone
abbreviation legend: LWCA – Lower Wolfcamp A; UWCA – Upper Wolfcamp
A; WCB –Wolfcamp B |
3. The
Durham Smith Fuente 201HL and 204HU were acquired as producing
wells |
|
See “Cautionary Statements” below for a discussion of the nature
of these production metrics.
Second Quarter Comparative Results
Resolute recorded net income available to common shareholders of
$10.7 million, or $0.47 per diluted share, on revenue of $71.0
million during the three months ended June 30, 2017. Included
in net income was $7.5 million of commodity derivative gains.
This compares to a net loss of $36.9 million, or $2.44 per share,
on revenue of $35.4 million during the three months ended June 30,
2016. The 2016 loss included commodity derivative losses of
$19.6 million.
For the six months ended June 30, 2017, Resolute recorded net
income available to common shareholders of $10.8 million, or $0.47
per diluted share, on revenue of $136.3 million. Included in
net income was $18.3 million of commodity derivative gains.
This compares to a net loss of $122.2 million or $8.10 per share,
on revenue of $54.4 million. The 2016 loss included commodity
derivative losses of $15.7 million and a non-cash impairment charge
of $58 million.
|
|
Second Quarter and Six Months 2017 Results
Compared to Second Quarter and Six Months 2016
Results |
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
($ thousands, except per-Boe
amounts) |
|
Production (MBoe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian |
|
|
1,673 |
|
|
|
511 |
|
|
|
2,915 |
|
|
|
780 |
|
Aneth |
|
|
543 |
|
|
|
569 |
|
|
|
1,074 |
|
|
|
1,120 |
|
Total production |
|
|
2,216 |
|
|
|
1,080 |
|
|
|
3,989 |
|
|
|
1,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily rate (Boe) |
|
|
24,355 |
|
|
|
11,865 |
|
|
|
22,041 |
|
|
|
10,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue per Boe
(excluding commodity derivative settlements) |
|
$ |
32.05 |
|
|
$ |
32.78 |
|
|
$ |
34.15 |
|
|
$ |
28.62 |
|
Revenue per Boe
(including commodity derivative settlements) |
|
$ |
32.79 |
|
|
$ |
51.81 |
|
|
$ |
34.51 |
|
|
$ |
54.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
71,026 |
|
|
$ |
35,390 |
|
|
$ |
136,252 |
|
|
$ |
54,392 |
|
Commodity derivative
settlements |
|
|
1,656 |
|
|
|
20,544 |
|
|
|
1,406 |
|
|
|
48,292 |
|
Revenue, including
derivative settlements |
|
|
72,682 |
|
|
|
55,934 |
|
|
|
137,658 |
|
|
|
102,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense |
|
$ |
19,890 |
|
|
$ |
15,689 |
|
|
$ |
38,246 |
|
|
$ |
29,506 |
|
Production and ad valorem taxes |
|
|
6,331 |
|
|
|
4,248 |
|
|
|
12,934 |
|
|
|
7,390 |
|
Depletion, depreciation, amortization and asset retirement
obligation accretion |
|
|
22,333 |
|
|
|
10,865 |
|
|
|
38,368 |
|
|
|
21,226 |
|
Impairment of proved oil and gas properties |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
58,000 |
|
General
and administrative expense |
|
|
9,472 |
|
|
|
7,530 |
|
|
|
19,887 |
|
|
|
16,498 |
|
Cash-settled incentive awards |
|
|
(1,413 |
) |
|
|
1,435 |
|
|
|
4,014 |
|
|
|
2,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
13,228 |
|
|
$ |
(36,906 |
) |
|
$ |
14,701 |
|
|
$ |
(122,218 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
32,442 |
|
|
$ |
28,362 |
|
|
$ |
61,360 |
|
|
$ |
51,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (a non-GAAP measure): During the second
quarter of 2017, Resolute generated $32.4 million of Adjusted
EBITDA, or $14.64 per Boe, a fourteen percent increase from the
prior year period, during which Resolute generated $28.4 million of
Adjusted EBITDA, or $26.27 per Boe. The increase in Adjusted
EBITDA was the result of increased revenue due to increased
production, partially offset by decreased commodity derivative
settlements and an increase in cash-settled incentive awards paid
as compared to the prior period.
During the first six months of 2017, Resolute generated $61.4
million of Adjusted EBITDA, or $15.38 per Boe, a nineteen percent
increase from the prior period, during which Resolute generated
$51.5 million of Adjusted EBITDA, or $27.11 per Boe. The
increase in Adjusted EBITDA resulted primarily from the reasons
noted above as well as increased revenue from increased commodity
pricing as compared to the 2016 period.
Production: Production for the quarter ended June 30,
2017, increased 105 percent to 2,216 MBoe, or 24,355 Boe per day,
as compared to 1,080 MBoe, or 11,865 Boe per day, during the second
quarter of 2016. During the first half of 2017, production
increased 110 percent to 3,989 MBoe, or 22,041 Boe per day, from
1,900 MBoe, or 10,441 Boe per day, during the first half of
2016. The increases from the comparable prior year periods
were attributable to positive results from the 2017 drilling and
completion program in the Permian Basin.
Production from the Company’s Permian Basin properties increased
more than 200 percent to 18,383 Boe per day, as compared to the
5,614 Boe per day produced in the second quarter of 2016, and
increased 33 percent from the 13,798 Boe per day produced during
the first quarter of 2017. During the first half of 2017,
production increased more than 250 percent to 16,103 Boe per day
from the 4,287 Boe per day produced during the first half of
2016.
Second quarter 2017 production from the Company’s Aneth Field
properties decreased four percent to 5,972 Boe per day as compared
to the 6,251 Boe per day produced in the second quarter of 2016,
and remained relatively unchanged from the 5,904 Boe per day
produced during the first quarter of 2017. During the first
half of 2017, production decreased four percent to 5,938 Boe per
day from the 6,154 per day produced during the first half of
2016.
Revenue: During the second quarter of 2017, Resolute
realized a 30 percent increase in adjusted revenue (revenue
including commodity derivative settlements), a non-GAAP measure, as
compared to the prior year quarter due to increased production
attributable to positive results from the drilling and completion
program in the Delaware Basin partially offset by decreased
derivative settlement gains as compared to the prior year
period. Adjusted revenue for the quarter was $72.7 million,
including the effect of commodity derivative settlement gains of
$1.7 million. During the second quarter of 2016, Resolute had
adjusted revenue of $55.9 million, including the effect of
commodity derivative settlement gains of $20.5 million.
During the first half of 2017, Resolute realized a 34 percent
increase in adjusted revenue as compared to the first half of 2016,
due to the reasons noted above. Adjusted revenue for the six
months ended June 30, 2017 was $137.7 million, including the effect
of commodity derivative settlement gains of $1.4 million. For
the six months ended June 30, 2016, Resolute had adjusted revenue
of $102.7 million, including the effect of commodity derivative
settlement gains of $48.3 million.
Operating Expenses: For the second quarter of 2017, LOE
increased $4.2 million, or 27 percent, to $19.9 million, or $8.97
per Boe, as compared to second quarter 2016 LOE of $15.7 million,
or $14.53 per Boe. The decrease in unit operating expense is
due to the significant increase in production from mid-length and
long lateral horizontal wells in the Delaware Basin, which
increased by a greater percentage than the associated LOE.
Production taxes increased by $2.1 million, or 49 percent, to $6.3
million (nine percent of revenue) from $4.2 million (twelve percent
of revenue) in 2016. Conversely, production taxes decreased
on a Boe basis to $2.86 per Boe in 2017 from $3.93 per Boe in
2016. The lower production and ad valorem taxes as a
percentage of revenue in 2017 as compared to 2016 is attributable
to the increase in the percentage of revenue realized in the state
of Texas, which has a lower tax rate than the Aneth Field
properties in Utah. This decrease is also the result of the
timing of the assessment of ad valorem taxes, as they are assessed
on January 1st of each year, based on the producing wells at that
point in time and are not updated for wells that come online
throughout the year.
For the first six months of 2017, LOE increased 30 percent to
$38.2 million, or $9.59 per Boe, from 2016 LOE of $29.5 million, or
$15.53 per Boe. The decrease in unit operating expense is due
to the reasons noted above. Production taxes increased by
$5.5 million, or 75 percent, to $12.9 million (ten percent of
revenue) as compared to $7.4 million (fourteen percent of revenue)
in 2016, and decreased on a Boe basis to $3.24 per Boe in 2017 from
$3.89 per Boe in 2016 due to the reasons noted above.
For the second quarter of 2017, depletion, depreciation,
amortization and accretion (“DD&A”) expenses increased 106
percent to $22.3 million as compared to the second quarter of 2016
DD&A expenses of $10.9 million as a result of the 105 percent
increase in production period over period. On a Boe basis,
DD&A expenses remained relatively unchanged at $10.08 per Boe
in 2017 compared to $10.06 per Boe in 2016.
For the first six months of 2017, DD&A expenses increased 81
percent to $38.4 million as compared to the first six months of
2016 expenses of $21.2 million principally as a result of the 110
percent increase in production period over period.
Conversely, DD&A expenses decreased on a Boe basis to $9.62 per
Boe in 2017 from $11.17 per Boe in 2016, which is attributable to
proved reserve quantities increasing by a greater percentage than
the associated capitalized costs period over period.
Pursuant to full cost accounting rules, we perform a ceiling
test each quarter on our proved oil and gas assets. No
impairment was recorded during the three or six months ended June
30, 2017. However, we recorded a $58 million non-cash
impairment of the carrying value of our proved oil and gas
properties during the six months ended June 30, 2016 as a result of
the ceiling test limitation.
General and Administrative Expense: Resolute’s general and
administrative expenses increased 26 percent to $9.5 million during
the second quarter of 2017, as compared to $7.5 million during the
same period in 2016. The $2.0 million increase primarily
resulted from increases in share based compensation due to a shift
from granting principally cash-based incentive awards in 2016 and
2015 to equity-based long-term incentive awards in 2017. On a
unit-of-production basis, general and administrative expenses
decreased 39 percent. Cash-based general and administrative
expense for the second quarter of 2017 was $6.5 million, or $2.95
per Boe, compared to $6.2 million, or $5.74 per Boe, in the
comparable 2016 period. Share-based compensation expense, a
non-cash item, represented $3.0 million for the second quarter of
2017 and $1.3 million for the second quarter of 2016.
For the first six months of 2017, general and administrative
expenses increased to $19.9 million, as compared to $16.5 million
during 2016. The $3.4 million, or 21 percent, increase
primarily resulted from the reason noted above as well as a
restoration of short-term incentive compensation awards, which had
been reduced during 2016 in response to lower commodity prices,
offset by an increase in the portion of general and administrative
expenses capitalized. Cash-based general and administrative
expense for the first half of 2017 was $14.1 million, or $3.54 per
Boe, compared to $13.0 million, or $6.82 per Boe in the comparable
2016 period. Share-based compensation expense represented
$5.8 million for the first six months of 2017 and $3.5 million for
the first six months of 2016.
Cash-settled Incentive Awards: We recorded a credit of
$1.4 million during the second quarter of 2017 for cash-settled
incentive award expenses as compared to expense of $1.4 million in
the second quarter of 2016. The decrease is attributable to a
decrease in the fair value of cash-settled stock appreciation
rights under the long-term incentive program, which are required to
be remeasured at each period end. Due to a decrease in the
price of Resolute common stock during the second quarter of 2017,
the remeasurement of the fair value of the awards yielded a lower
fair value than at March 31, 2017. As a result, a credit was
recorded during the second quarter of 2017. Actual cash
payments for the current quarter were $7.7 million.
For the six months ended June 30, 2017, cash-settled incentive
award expenses increased to $4.0 million as compared to $2.2
million for the six months ended June 30, 2016. The 2017
increase in expense is a result of the grant of time- and
performance-based restricted stock awards, the achievement of
multiple performance targets under the performance-based restricted
cash awards as well as cash-settled stock appreciation rights under
the long-term incentive program that are based on the Company’s
common stock price. Actual cash payments during the 2017
period were $11.3 million.
Capital Expenditures: During the quarter ended June 30,
2017, Resolute incurred oil and gas related capital expenditures of
approximately $93.7 million, excluding the Delaware Basin Bronco
Acquisition of $161.3 million and capitalized interest of $3.7
million. During the first six months of 2017, Resolute
incurred oil and gas related capital expenditures of approximately
$147.1 million, excluding the Delaware Basin Bronco Acquisition of
$161.3 million and capitalized interest of $6.2 million.
These capital investments were primarily for drilling and
completion, and facility and infrastructure projects in the
Delaware Basin.
Liquidity and Capital Resources: Outstanding indebtedness
of $625 million at June 30, 2017, consisted of $100 million in
revolving credit facility debt and $525 million of senior notes,
compared to total indebtedness of $538.3 million at December 31,
2016, an increase of $86.7 million. During the first half of
2017, we repaid all amounts outstanding on the Secured Term Loan
Facility and entered into the Third Amended and Restated Credit
Agreement with an initial borrowing base of $150 million.
Pursuant to the spring borrowing base redetermination, our
borrowing base was increased to $225 million, effective April 17,
2017. Additionally, in May 2017, Resolute issued an
additional $125 million aggregate principal amount of the Company’s
8.50% senior notes due 2020, under the same indenture as the $400
million senior notes that were previously issued. As a result
of the issuance of the additional senior notes, the borrowing base
was reduced to $218.8 million.
|
RESOLUTE ENERGY CORPORATION |
|
Condensed Consolidated Statements of
Operations (Unaudited) |
($ in thousands, except per share
data) |
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
60,703 |
|
|
$ |
33,483 |
|
|
$ |
118,362 |
|
|
$ |
51,278 |
|
Gas |
|
|
7,216 |
|
|
|
1,210 |
|
|
|
12,173 |
|
|
|
2,188 |
|
Natural
gas liquids |
|
|
3,107 |
|
|
|
697 |
|
|
|
5,717 |
|
|
|
926 |
|
Total
revenue |
|
|
71,026 |
|
|
|
35,390 |
|
|
|
136,252 |
|
|
|
54,392 |
|
Operating
expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating |
|
|
19,890 |
|
|
|
15,689 |
|
|
|
38,246 |
|
|
|
29,506 |
|
Production and ad valorem taxes |
|
|
6,331 |
|
|
|
4,248 |
|
|
|
12,934 |
|
|
|
7,390 |
|
Depletion, depreciation, amortization, and asset retirement
obligation accretion |
|
|
22,333 |
|
|
|
10,865 |
|
|
|
38,368 |
|
|
|
21,226 |
|
Impairment of proved oil and gas properties |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
58,000 |
|
General and administrative |
|
|
9,472 |
|
|
|
7,530 |
|
|
|
19,887 |
|
|
|
16,498 |
|
Cash-settled incentive awards |
|
|
(1,413 |
) |
|
|
1,435 |
|
|
|
4,014 |
|
|
|
2,233 |
|
Total
operating expenses |
|
|
56,613 |
|
|
|
39,767 |
|
|
|
113,449 |
|
|
|
134,853 |
|
Income (loss) from
operations |
|
|
14,413 |
|
|
|
(4,377 |
) |
|
|
22,803 |
|
|
|
(80,461 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net |
|
|
(8,779 |
) |
|
|
(12,983 |
) |
|
|
(26,476 |
) |
|
|
(26,058 |
) |
Commodity
derivative instruments gain (loss) |
|
|
7,458 |
|
|
|
(19,552 |
) |
|
|
18,298 |
|
|
|
(15,711 |
) |
Other
income |
|
|
136 |
|
|
|
6 |
|
|
|
76 |
|
|
|
12 |
|
Total
other expense |
|
|
(1,185 |
) |
|
|
(32,529 |
) |
|
|
(8,102 |
) |
|
|
(41,757 |
) |
Net income (loss) |
|
|
13,228 |
|
|
|
(36,906 |
) |
|
|
14,701 |
|
|
|
(122,218 |
) |
Preferred
stock dividends |
|
|
(2,538 |
) |
|
|
— |
|
|
|
(3,935 |
) |
|
|
— |
|
Net income (loss)
available to common shareholders |
|
$ |
10,690 |
|
|
$ |
(36,906 |
) |
|
$ |
10,766 |
|
|
$ |
(122,218 |
) |
Net income (loss) per
common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.49 |
|
|
$ |
(2.44 |
) |
|
$ |
0.49 |
|
|
$ |
(8.10 |
) |
Diluted |
|
|
0.47 |
|
|
|
(2.44 |
) |
|
$ |
0.47 |
|
|
$ |
(8.10 |
) |
Weighted average common
shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
21,917 |
|
|
|
15,155 |
|
|
|
21,828 |
|
|
|
15,096 |
|
Diluted |
|
|
22,894 |
|
|
|
15,155 |
|
|
|
22,836 |
|
|
|
15,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Net Income (Loss) to Adjusted
EBITDA
In this press release, the term “Adjusted EBITDA” is used.
Adjusted EBITDA is a non-GAAP financial measure and is equivalent
to earnings before interest, income taxes, depreciation, depletion,
amortization and accretion expenses, stock-based compensation,
cash-settled incentive awards, mark-to-market commodity derivative
gain (loss), gains and losses on the sale of assets and ceiling
write-down of oil and gas properties. Resolute’s management
believes Adjusted EBITDA is an important financial measurement tool
that facilitates comparison of our operating performance, and
provides information about the Company’s ability to service or
incur indebtedness and pay for its capital expenditures. This
information differs from measures of performance determined in
accordance with GAAP and should not be considered in isolation or
as a substitute for measures of performance prepared in accordance
with GAAP. This measure is not necessarily indicative of
operating profit or cash flow from operating activities as
determined under GAAP and may not be equivalent to similarly titled
measures of other companies. The table below reconciles
Resolute’s net income (loss) to Adjusted EBITDA.
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
($ in thousands) |
|
|
($ in thousands) |
|
Net income (loss) |
|
$ |
13,228 |
|
|
$ |
(36,906 |
) |
|
$ |
14,701 |
|
|
$ |
(122,218 |
) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net |
|
|
8,779 |
|
|
|
12,983 |
|
|
|
26,476 |
|
|
|
26,058 |
|
Income
tax (benefit) loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Depletion, depreciation, amortization and asset retirement
obligation accretion |
|
|
22,333 |
|
|
|
10,865 |
|
|
|
38,368 |
|
|
|
21,226 |
|
Impairment of proved oil and gas properties |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
58,000 |
|
Stock-based compensation |
|
|
2,979 |
|
|
|
1,409 |
|
|
|
5,952 |
|
|
|
3,733 |
|
Cash-settled incentive awards accrued |
|
|
(1,413 |
) |
|
|
1,435 |
|
|
|
4,014 |
|
|
|
2,233 |
|
Cash-settled incentive awards paid |
|
|
(7,662 |
) |
|
|
(1,520 |
) |
|
|
(11,259 |
) |
|
|
(1,520 |
) |
Mark-to-market (gain) loss |
|
|
(5,802 |
) |
|
|
40,096 |
|
|
|
(16,892 |
) |
|
|
64,003 |
|
Total
adjustments |
|
|
19,214 |
|
|
|
65,268 |
|
|
|
46,659 |
|
|
|
173,733 |
|
Adjusted EBITDA |
|
$ |
32,442 |
|
|
$ |
28,362 |
|
|
$ |
61,360 |
|
|
$ |
51,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Call Information
Resolute will host an investor call on August 8, 2017, at 7:30
AM EDT. To participate in the call please dial (800) 474 - 8920
from the United States or Canada or (719) 457- 2605 from outside
the U.S. and Canada. Participants should dial in five to ten
minutes before the scheduled time and must be on a touchtone
telephone to ask questions. A replay of the call will be available
through August 15, 2017, by dialing (844) 512-2921 from the U.S. or
Canada, or (412) 317- 6671 from outside the U.S. The conference
call replay number is 5047730.
Cautionary Statements
This press release includes “forward-looking statements” within
the meaning of the safe harbor provisions of the United States
Private Securities Litigation Reform Act of 1995. Words such as
“expect,” “estimate,” “project,” “budget,” “forecast,”
“anticipate,” “intend,” “plan,” “may,” “will,” “could,” “should,”
“poised,” “believes,” “predicts,” “potential,” “continue,” and
similar expressions are intended to identify such forward-looking
statements. Such forward looking statements include statements
regarding 2017 production guidance; 2017 oil percentage guidance;
anticipated capital expenditures and activity in 2017; future
financial and operating results; liquidity and availability of
capital; the anticipated execution of definitive documentation
relating to the disposition of Aneth Field and the anticipated
closing thereof; future infrastructure and other capital projects;
future production, reserve growth and decline rates; the impact of
well interference and the effectiveness of operational adjustments
with respect thereto; expected timing of drilling and completion of
pad wells and the timing of the production contribution thereof;
our plans and expectations regarding our future development
activities including drilling, deepening, recompleting, fracing and
refracing wells, the number of such potential projects, locations
and productive intervals, and the prospectivity of our properties
and acreage. Forward-looking statements in this press release
include matters that involve known and unknown risks, uncertainties
and other factors that may cause actual results, levels of
activity, performance or achievements to differ materially from
results expressed or implied by this press release. Such risk
factors include, among others: commodity prices; the volatility of
oil and gas prices including the price realized by Resolute for the
oil and gas it sells; inaccuracy in reserve estimates and expected
production rates; the discovery, estimation, development and
replacement by Resolute of oil and gas reserves and the risks
associated with the potential writedown of reserves; the future
cash flow, liquidity and financial position of Resolute; Resolute’s
level of indebtedness and our ability to fulfill our obligations
under the senior notes, our credit facility, and any additional
indebtedness that we may incur; potential borrowing base reductions
under our revolving credit facility; the success of the business
and financial strategy, hedging strategies and plans of Resolute;
the amount, nature and timing of capital expenditures of Resolute,
including future development costs; the availability of additional
capital and financing, including the capital needed to pursue our
acquisition strategy and our drilling and development plans for our
properties, on terms acceptable to us or at all; the effectiveness
of Resolute’s CO2 flood program; uncertainty surrounding timing of
identifying drilling locations and necessary capital to drill such
locations; the potential for down-spacing, infill or multi-lateral
drilling in the Permian Basin or obstacles thereto; the timing of
issuance of permits and rights of way; the timing and amount of
future production of oil and gas; availability of drilling,
completion and production personnel, supplies and equipment; the
completion and success of exploratory drilling on our properties;
potential delays in the completion, commissioning and optimization
schedule of Resolute’s facilities construction projects or any
potential breakdown of such facilities; operating costs and other
expenses of Resolute; the success of prospect development and
property acquisition of Resolute; timing of installation of
gathering and processing infrastructure in new areas of
development, including Resolute’s dependence on third parties for
such items; the success of Resolute in marketing oil and gas;
competition in the oil and gas industry; the impact of weather and
the occurrence of disasters, such as fires, floods and other events
and natural disasters; environmental liabilities; anticipated
supply of CO2, which is currently sourced exclusively under a
contract with Kinder Morgan CO2 Company, L.P.; potential power
supply interruptions, limitations or delays; operational problems
or uninsured or underinsured losses affecting Resolute’s operations
or financial results; adverse changes in government regulation and
taxation of the oil and gas industry, including the potential for
increased regulation of underground injection, fracing operations
and venting/flaring; potential climate related change regulations;
risks and uncertainties associated with horizontal drilling and
completion techniques; the availability of water and our ability to
adequately treat and dispose of water during and after drilling and
completing wells; changes in derivatives regulation; developments
in oil-producing and gas- producing countries; Resolute’s
relationship with the Navajo Nation and the local communities in
the areas in which Resolute operates; and cyber security risks.
Actual results may differ materially from those contained in the
forward looking statements in this press release. Resolute
undertakes no obligation and does not intend to update these
forward-looking statements to reflect events or circumstances
occurring after the date of this press release. You are cautioned
not to place undue reliance on these forward-looking statements,
which speak only as of the date of this press release. You are
encouraged to review “Cautionary Note Regarding Forward Looking
Statements” and “Item 1A - Risk Factors” and all other disclosures
appearing in the Company’s Form 10-K for the year ended December
31, 2016, and subsequent filings with the Securities and Exchange
Commission for further information on risks and uncertainties that
could affect the Company’s businesses, financial condition and
results of operations. All forward-looking statements are qualified
in their entirety by this cautionary statement.
Lateral lengths of wells described in this release are
indicative only. Actual completed lateral lengths depend on various
considerations such as leaseline offsets. Standard length laterals,
sometimes referred to as 5,000 foot laterals, are laterals with
completed length generally between 4,000 feet and 5,500 feet.
Mid‐length laterals, sometimes referred to as 7,500 foot laterals,
are laterals with completed length generally between 6,500 feet and
8,000 feet. Long laterals, sometimes referred to as 10,000 foot
laterals, are laterals with completed length generally longer than
8,000 feet.
Finally, production rates, including 24 hour, 30 day and 60 day
peak IP rates, for both our wells and for wells that are operated
by others are limited data points in each well’s productive
history. Also, different operators have different operating
philosophies, particularly early in the life of a well. Finally,
the way we calculate and report 24 hour, 30 day and 60 day peak IP
rates and the methodologies used by others may not be consistent,
thus the values reported may not be directly and meaningfully
comparable. As a result, these metrics may not be indicative or
predictive of future production rates, EUR or economic rates of
return from such wells and should not be relied upon for such
purpose. You are urged to consider closely the disclosure in
Resolute’s Annual Report on Form 10- K filed on March 13, 2017, in
particular the factors described under “Risk Factors.”
About Resolute Energy Corporation
Resolute is an independent oil and gas company focused on the
acquisition and development of unconventional oil and gas
properties in the Delaware Basin portion of the Permian Basin of
west Texas. Resolute also operates Aneth Field, located in the
Paradox Basin in Utah. For more information, visit
www.resoluteenergy.com. The Company routinely posts important
information about the Company under the Investor Relations section
of its website. The Company's common stock is traded on the NYSE
under the ticker symbol "REN."
Contact:
HB Juengling
Vice President - Investor Relations
Resolute Energy Corporation
303-534-4600, extension 1555
hbjuengling@resoluteenergy.com
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