Chaparral Energy, Inc. (NYSE: CHAP) announced today its second
quarter 2019 financial and operational results. The company will
hold its quarterly earnings call Thursday, August 8, at 9 a.m.
Central.
Recent Highlights
- Achieved second quarter 2019 total production of 28.3 thousand
barrels of oil equivalent per day (MBoe/d), 1.5 MBoe/d above
midpoint and 0.8 MBoe/d above high end of guidance and a 36%
increase from the first quarter of 2019
- Increased STACK production to 23.8 MBoe/d in the second
quarter, 1.5 MBoe/d above midpoint and 0.8 MBoe/d above high end of
guidance and a 50% increase from the first quarter of 2019
- Reported net loss of $45.2 million for the second quarter of
2019, or $0.99 per share, which included a $63.6 million non-cash
ceiling test impairment charge, partially offset by a $17.6 million
non-cash derivative gain
- Grew second quarter 2019 adjusted EBITDA, as defined below, to
$43.7 million, an increase of 54% compared to the previous
quarter
- Decreased total company and STACK lease operating expense per
Boe (LOE/Boe) to $5.19 and $3.90, respectively, a 21% decrease from
the previous quarter for both
- Lowered cash general and administrative expense per Boe
(G&A/Boe), as defined below, to $2.52, which represents a 27%
decrease from the previous quarter
- Updated full year 2019 guidance, including a 5% reduction in
total capital expenditures compared to the previous midpoint of the
company’s guidance and decreases in LOE/Boe and cash G&A/Boe
expense, while reaffirming its previously stated production
range
- Implemented proactive G&A cost reduction initiatives
resulting in corporate workforce being reduced by 23% year to date
and expected annualized G&A reductions of approximately 20% to
25% to better align G&A with current industry conditions
- Continued drilling and completion execution improvements, with
recent average Osage and Merge Miss well costs declining materially
compared to the company’s 2018 average, ranging from $3.5 to $4.0
million in 2019
- Finalized an agreement to sell the current corporate
headquarters facilities; proceeds from the sale will be used to
eliminate related debt of approximately $8.3 million and is
expected to result in annual savings of approximately $1
million
- Announced 120-day initial production (IP) results above oil
type curve expectations from its 11-well cube style, co-development
Foraker spacing test in Canadian County
“Since becoming a publicly traded company in 2017, we have
consistently delivered operational results within or above our
guidances ranges and this quarter is no exception,” said Chief
Executive Officer Earl Reynolds. “We continue to demonstrate the
considerable value of our differentiated acreage position through
our outstanding operational execution. Our total company production
increased to 28.3 MBoe/d, our adjusted EBITDA grew to $43.7 million
and our operational expenses and capital costs per well continue to
decline. Through the first half of this year we have been able to
reduce our average well cost by approximately 15% to 20% compared
to 2018 for our Merge Miss and Osage drilling program. Our ability
to consistently execute, coupled with the operational efficiencies
we continue to capture, including increases in drilling footage per
day, more efficient frac designs and doubling the number of frac
stages completed per day, have all contributed to our reduced well
costs. These efficiencies allow us to drill and complete wells
faster, drive down costs and reduce cycle times, which all
positively impact well economics.”
“In addition, we continue to be very pleased with the
outstanding drilling, completion and production results from our
cube style, co-development Foraker spacing test, which we brought
online in late March,” said Reynolds. “The average 120-day IP oil
rates for both the Meramec and Woodford wells continue to
outperform type curve at 148% and 101% respectively. I am extremely
proud of our execution on this project and we are applying the
learnings from this one-mile, full section development moving
forward. We are reconfiguring our second half drilling schedule
based on these results and plan to begin drilling the Greenback,
which is a Canadian County Meramec full section development in
close proximity to the Foraker, in the fourth quarter of this
year.”
“For the full year of 2019, we are updating our corporate
guidance. We continue to proactively take measures to reduce costs
across our entire business. As a result of our G&A cost
reduction initiatives, we are reducing our G&A per Boe guidance
by 11% and as a result of our operational success are lowering our
STACK LOE/Boe guidance by 4%. We are reaffirming our original
full-year 2019 production estimates but lowering our capital
expenditure guidance by approximately 5%. As we have discussed in
the past, the overall timing of our production growth will be
uneven from quarter to quarter due to the drilling of larger pads
and full section developments. As such, we expect our third quarter
total production guidance to be between 26.0 to 27.5 MBoe/d. While
we continue to expect strong growth, the timing of completions and
performance of our new wells will impact our quarter-to-quarter
rates going forward,” said Reynolds. “We are proud of the
differentiated STACK/Merge position we have built and how we have
been able to execute operationally. We remain focused on generating
strong adjusted EBITDA, which is driven by our operational
execution, capital discipline and cost management, and maintaining
a strong balance sheet. We are continuing to grow production and
proactively taking additional steps that are allowing us to move
progressively closer to achieving cash flow neutrality as we create
long-term value for our shareholders.”
Operational Update Chaparral’s STACK production
for the second quarter of 2019 was 23.8 MBoe/d, while total company
production was 28.3 MBoe/d, both of which are above the high end of
the company’s second quarter 2019 guidance range. As expected, due
to timing associated with production from the company’s multi-well
spacing tests, total company and STACK production increased
significantly on a quarter-over-quarter basis by 36% and 50%,
respectively. On a year-over-year basis, STACK production increased
80%, while total company production increased 55%, excluding 2018
divestitures. Overall, total company production consisted of 34%
oil, 29% natural gas liquids (NGLs) and 37% natural gas in the
second quarter of 2019.
Chaparral completed the drilling of its 11-well cube style,
co-development Foraker spacing test in Canadian County during the
first quarter of 2019 and finalized completion of the wells early
in the second quarter. The multi-well test was drilled from three
pads into three distinct drilling targets, the Upper Meramec, Lower
Meramec and Woodford. There were four wells drilled into the Upper
Meramec, five wells in the Lower Meramec and two wells in the
Woodford. The average lateral length of the Meramec and Woodford
wells were 4,934 and 4,949 feet, respectively. To maximize
completion efficiency, the wells were fracture stimulated in a
manner which was designed to create the greatest amount of near
wellbore complexity, while maintaining sufficient pressure
boundaries to minimize inter-well frac communication.
The average 120-day IP rate for all 11 wells was 877 Boe/d, with
36% oil and 67% liquids. The nine Meramec wells had an average
120-day IP rate of 967 Boe/d, with 36% oil and 67% liquids. All
nine Meramec wells are significantly outperforming the company’s
oil type curve expectations with an average 120-day oil IP rate at
148% of type curve. The two Woodford wells had an average 120-day
IP rate of 468 Boe/d, with 35% oil and 67% liquids. These Woodford
wells are outperforming the company’s oil type curve expectations,
with an average 120-day oil IP rate at 101% of type curve.
The company continues to see overall strong results from
additional spacing tests. These tests are geologically driven, with
some tests performing better than others. Given the performance of
the Denali, Foraker and other recent tests, the company is now
planning another Meramec full section development in Canadian
County, with the drilling of the six to eight well Greenback
project in the fourth quarter as it continues testing the number of
wells per section to optimize long-term, full section development.
The growth trajectory of Chaparral’s STACK/Merge production will
continue to be impacted by spacing tests moving forward, with
production dependent on how many wells are completed and brought
online in any given quarter.
The company had 28 new gross operated STACK wells with first
sales during the second quarter, three of which were part of its
drilling joint venture. In addition, the full production impact of
its 11-well cube style, co-development Foraker spacing test in
Canadian County contributed materially to the increased production
during the second quarter. Of its 28 wells with first sales, 14
were in Canadian County, 10 in Kingfisher County and four in
Garfield County. Chaparral currently plans to operate three rigs
for the remainder of 2019, with all capital in the second half of
2019 allocated to Canadian and Kingfisher counties.
Chaparral’s total oil and natural gas capital expenditures
(CAPEX) during the second quarter were $75.7 million, of which
$69.1 million was associated with the STACK. Of its STACK CAPEX,
$64.7 million was related to drilling and completion (D&C)
activities, which included $2.1 million of non-operated CAPEX.
Additionally, $3.2 million was invested in acquisition activities
and $1.8 million in workovers and other enhancement capital.
Capital Expenditures (in millions) |
Q2 2019 |
STACK Acquisitions1 |
$3.2 |
STACK D&C2 |
$64.7 |
STACK Enhancements |
$1.2 |
Total STACK |
$69.1 |
Other Enhancements |
$0.6 |
Corporate Allocations3 |
$6.0 |
Total CAPEX |
$75.7 |
1Includes non-cash acreage trades of $0.6
million 2Includes non-operated costs of $2.1 and $3.5
million of drilling joint venture 3Includes
capitalized G&A, capitalized interest and asset retirement
obligations
Financial Summary Chaparral reported a net loss
of $45.2 million, or $0.99 per share, during the second quarter of
2019. This included a $63.6 million non-cash ceiling test
impairment charge primarily due to a decrease in the prices used to
estimate its reserves, partially offset by a $17.6 million non-cash
gain in the fair value of hedge derivative instruments. Chaparral’s
adjusted EBITDA for the second quarter was up 54% on a
quarter-over-quarter basis to $43.7 million, primarily due to
increased production. On a year-over-year basis, adjusted EBITDA
was up 62% primarily due to higher production and lower operating
costs. Total gross commodity sales for the second quarter of 2019
were $72.5 million, which included $51.0 million from oil, $11.0
million from NGLs and $10.5 million from natural gas. This
represents a 36% quarter-over-quarter increase compared to $53.2
million in the first quarter of 2019 and an increase of 16%
year-over-year compared to $62.3 million in the second quarter of
2018.
Chaparral’s average realized price for crude oil, excluding
derivative settlements, increased to $58.41 per barrel in the
second quarter of 2019, up 10% from the first quarter of 2019 and
down 12% from the second quarter of 2018. Chaparral’s realized NGL
price during the second quarter of 2019 was $14.72 per barrel,
which represents a 19% quarter-over-quarter decrease and a 40%
year-over-year decrease. The company’s realized natural gas price
during the second quarter of 2019 was $1.83 per thousand cubic feet
(Mcf), which represents a decrease of 27% compared to the first
quarter of 2019 and a decrease of 9% compared to the second quarter
of 2018.
Total company LOE for the second quarter of 2019 was $13.4
million, or $5.19 per Boe, which was down 21% compared to $6.56 per
Boe in the first quarter of 2019 and down 38% compared to $8.36 per
Boe in the second quarter of 2018. Chaparral’s STACK LOE/Boe for
the second quarter of 2019 was $3.90 per Boe, which was down 21%
from $4.96 in the previous quarter and down 26% from $5.30 in the
second quarter of 2018. The decreases were driven primarily by the
increase in production due to timing of new wells being brought
online and reduced saltwater disposal costs along with efficiency
improvements in the field operations.
To better align Chaparral’s G&A and overhead expenses with
current industry conditions, the company recently implemented a
workforce reduction. Since the beginning of 2019, the company has
reduced its corporate workforce by 23% and implemented cost
reduction initiatives that will result in estimated annualized
G&A savings of 20% to 25%. The full impact of these reductions
will be realized in 2020, with initial savings flowing through in
the second half of 2019. Chaparral’s net G&A expense was $7.3
million, or $2.84 per Boe, during the second quarter of 2019, a
reduction of 36% compared to the first quarter of 2019 and a
reduction of 38% compared to the second quarter of 2018. Adjusted
for non-cash compensation, Chaparral’s cash G&A expense per Boe
in the second quarter of 2019 was $2.52, which is a 27% reduction
compared to the first quarter of 2019 and a 31% decrease compared
to the second quarter of 2018.
Balance Sheet and LiquidityThe company’s $325
million borrowing base was reaffirmed during its semi-annual spring
redetermination, which closed on May 2, 2019. As of June 30, 2019,
Chaparral had approximately $33 million in cash and cash
equivalents and $85 million drawn under its $325 million borrowing
base. The company’s balance sheet remains strong with no
significant debt maturities due until 2022.
On August 5, Chaparral entered into an agreement to sell the
building housing its headquarters. Proceeds from the sale of the
building will be used to eliminate related debt of approximately
$8.3 million and Chaparral estimates annualized savings of
approximately $1 million will be achieved.
In the second quarter of 2019, the company had a non-cash
ceiling test impairment of $63.6 million, primarily due to a
decrease in the price used to estimate its reserves.
Updated GuidanceChaparral expects capital
expenditures in the second half of 2019 to be lower than the first
half due to the reduction from four to three operated rigs,
drilling and completion efficiencies per well, lower than
anticipated non-operated activity and lower acquisition capital.
The company is reducing full year 2019 CAPEX guidance to $260 to
$285 million, which is a reduction from the midpoint of the initial
guidance of approximately 5%. Chaparral is also lowering its
guidance ranges for LOE/Boe to $4.90 to $5.40, STACK LOE/Boe to
$3.60 to $4.10 and cash G&A/Boe to $2.50 to $3.00 per Boe as a
result of cost reduction initiatives.
The company is also re-affirming its original production
guidance range of 25.0 to 27.0 MBoe/d for the full year 2019.
Chaparral expects third quarter 2019 total company production to be
between 26.0 and 27.5 MBoe/d and total STACK production to between
21.5 and 23.0 MBoe/d. The decline from its second quarter actual
production is primarily due to the impact of reducing operated
activity from four rigs to three in late March and the associated
timing of new operated development wells being placed online, going
from 28 wells in the second quarter to an estimated 10 to 15 in the
third quarter.
Full Year 2019 Guidance |
Updated 2019E |
Previous 2019E |
Total Capital Expenditures (in
millions) |
$260 - $285 |
$275 - $300 |
LOE/Boe |
$4.90 - $5.40 |
$5.00 - $5.50 |
STACK LOE/Boe |
$3.60 - $4.10 |
$3.75 - $4.25 |
Cash G&A/Boe |
$2.50 - $3.00 |
$2.85 - $3.35 |
Total Company Production
(MBoe/d) |
25.0 - 27.0 |
25.0 - 27.0 |
STACK Production (MBoe/d) |
21.0 - 23.0 |
21.0 - 23.0 |
Earnings Call InformationChaparral will hold
its financial and operating results call on Thursday, August 8, at
9 a.m. Central. Interested parties may access the call toll-free at
877-790-7727 and ask for the Chaparral Energy conference call 10
minutes prior to the start time. The conference ID number is
1291065. A live webcast of the call will also be available
through the Investor section of the company’s website.
For those who cannot listen to the live call, a recording will be
available shortly after the call’s conclusion
at chaparralenergy.com/investors.
The company has also provided an updated investor presentation
for the quarter, which along with its form 10-Q, will be available
at chaparralenergy.com/investors, as well as the Securities and
Exchange Commission’s website at sec.gov.
Statements made in this release contain “forward-looking
statements.” These statements are based on certain assumptions and
expectations made by Chaparral, which reflect management’s
experience, estimates and perception of historical trends, current
conditions, anticipated future developments, potential for reserves
and drilling, completion of current and future acquisitions and
growth, benefits of acquisitions, future competitive position and
other factors believed to be appropriate. These forward-looking
statements are subject to certain risks, trends and uncertainties
that could cause actual results to differ materially from those
projected. Among those risks, trends and uncertainties are our
ability to find oil and natural gas reserves that are economically
recoverable, the volatility of oil and natural gas prices, the
uncertain economic conditions in the United States and globally,
the decline in the reserve values of our properties that may result
in ceiling test write-downs, our ability to replace reserves and
sustain production, our estimate of the sufficiency of our existing
capital sources, our ability to raise additional capital to fund
cash requirements for future operations, the uncertainties involved
in prospect development and property acquisitions or dispositions
and in projecting future rates of production or future reserves,
the timing of development expenditures and drilling of wells, the
impact of natural disasters on our present and future operations,
the impact of government regulation and the operating hazards
attendant to the oil and natural gas business. Initial production
(IP) rates are discreet data points in each well’s productive
history. These rates are sometimes actual rates and sometimes
extrapolated or normalized rates. As such, the rates for a
particular well may decline over time and change as additional data
becomes available. Peak production rates are not necessarily
indicative or predictive of future production rates or economic
rates of return from such wells and should not be relied upon for
such purpose. The ability of the company or the relevant operator
to maintain expected levels of production from a well is subject to
numerous risks and uncertainties, including those referenced and
discussed above. In addition, methodology the company and other
industry participants utilize to calculate peak IP rates may not be
consistent and, as a result, the values reported may not be
directly and meaningfully comparable. Please read “Risk Factors” in
our annual reports, form 10-K or other public filings. We undertake
no duty to update or revise these forward-looking
statements.
About Chaparral Chaparral Energy (NYSE: CHAP)
is an independent oil and natural gas exploration and production
company headquartered in Oklahoma City. Founded in 1988, Chaparral
is a pure-play operator focused in Oklahoma’s highly economic
STACK/Merge Play, where it has approximately 130,000 net acres
primarily in Kingfisher, Canadian and Garfield counties. The
company has approximately 221,000 net surface acres in the
Mid-Continent region. For more information, visit
chaparralenergy.com.
Investor Contact Scott Pittman Chief Financial
Officer405-426-6700investor.relations@chaparralenergy.com
Consolidated Statement of
Operations (unaudited) |
|
|
(in thousands, except share and per share
data) |
Three months ended |
Six Months Ended |
Revenues: |
June 30, 2019 |
March 31, 2019 |
June 30, 2018 |
June 30, 2019 |
June 30, 2018 |
Net commodity sales |
66,707 |
|
48,619 |
|
58,427 |
|
115,326 |
|
116,316 |
|
Sublease revenue |
1,198 |
|
1,198 |
|
1,198 |
|
2,396 |
|
2,396 |
|
Total revenues |
67,905 |
|
49,817 |
|
59,625 |
|
117,722 |
|
118,712 |
|
Lease operating |
13,371 |
|
12,294 |
|
15,009 |
|
25,665 |
|
29,552 |
|
Production taxes |
3,802 |
|
2,880 |
|
2,768 |
|
6,682 |
|
5,445 |
|
Depreciation, depletion and amortization |
30,282 |
|
23,715 |
|
20,407 |
|
53,997 |
|
41,513 |
|
Loss on impairment of oil and gas assets |
63,593 |
|
49,722 |
|
— |
|
113,315 |
|
— |
|
Loss on impairment of other assets |
6,407 |
|
— |
|
— |
|
6,407 |
|
— |
|
General and administrative |
7,315 |
|
8,313 |
|
8,190 |
|
15,628 |
|
19,697 |
|
Cost reduction initiatives |
— |
|
— |
|
824 |
|
— |
|
824 |
|
Other |
403 |
|
403 |
|
403 |
|
806 |
|
1,231 |
|
Total costs and expenses |
125,173 |
|
97,327 |
|
47,601 |
|
222,500 |
|
98,262 |
|
Operating (loss) income |
(57,268 |
) |
(47,510 |
) |
12,024 |
|
(104,778 |
) |
20,450 |
|
Non-operating income (expense): |
|
|
|
|
|
Interest expense |
(5,571 |
) |
(4,564 |
) |
(1,739 |
) |
(10,135 |
) |
(3,110 |
) |
Derivative gains (losses) |
17,734 |
|
(51,016 |
) |
(32.286 |
) |
(33,282 |
) |
(48,787 |
) |
Gain (loss) on sale of assets |
491 |
|
(1 |
) |
469 |
|
490 |
|
(575 |
) |
Other income, net |
(302 |
) |
14 |
|
19 |
|
(288 |
) |
104 |
|
Net non-operating income (expense) |
12,352 |
|
(55,567 |
) |
(33,537 |
) |
(43,215 |
) |
(52,368 |
) |
Reorganization items, net |
(313 |
) |
(463 |
) |
(480 |
) |
(776 |
) |
(1,517 |
) |
Loss before income taxes |
(45,229 |
) |
(103,540 |
) |
(21,993 |
) |
(148,769 |
) |
(33,435 |
) |
Income tax expense |
— |
|
— |
|
— |
|
— |
|
— |
|
Net (loss) |
(45,229 |
) |
(103,540 |
) |
(21,993 |
) |
(148,769 |
) |
(33,435 |
) |
Earnings per share: |
|
|
|
|
|
Basic for Class A and Class B |
(0.99 |
) |
(2.28 |
) |
(0.49 |
) |
(3.27 |
) |
(0.74 |
) |
Diluted for Class A and Class B |
(0.99 |
) |
(2.28 |
) |
(0.49 |
) |
(3.27 |
) |
(0.74 |
) |
Weighted average shares used to compute earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic for Class A and Class B |
|
45,641,797 |
|
|
45,456,214 |
|
|
45,338,650 |
|
|
45,549,518 |
|
45,241,513 |
|
Diluted for Class A and Class B |
|
45,641,797 |
|
|
45,456,214 |
|
|
45,338,650 |
|
|
45,549,518 |
|
45,241,513 |
|
Consolidated Balance
Sheets (Unaudited) |
|
|
|
(dollars in thousands, except share data) |
June 30, 2019 |
March 31, 2019 |
December 31, 2018 |
Assets |
|
|
|
Current
assets: |
|
|
|
Cash and cash equivalents |
$ |
32,648 |
|
$ |
11,118 |
|
$ |
37,446 |
|
Accounts receivable, net |
|
52,686 |
|
|
62,652 |
|
|
66,087 |
|
Inventories, net |
|
4,142 |
|
|
3,923 |
|
|
4,059 |
|
Prepaid expenses |
|
1,774 |
|
|
2,593 |
|
|
2,814 |
|
Derivative instruments |
|
4,524 |
|
|
— |
|
|
24,025 |
|
Total
current assets |
|
95,774 |
|
|
80,286 |
|
|
134,431 |
|
Property
and equipment, net |
|
36,265 |
|
|
42,558 |
|
|
43,096 |
|
Right of
use assets from operating leases |
|
9,005 |
|
|
12,064 |
|
|
— |
|
Oil and
natural gas properties, using the full cost method: |
|
|
|
Proved |
|
1,107,203 |
|
|
976,025 |
|
|
915,333 |
|
Unevaluated (excluded from the amortization base) |
|
426,738 |
|
|
484,021 |
|
|
466,616 |
|
Accumulated depreciation, depletion, amortization and
impairment |
|
(384,401 |
) |
|
(292,679 |
) |
|
(221,431 |
) |
Total oil and natural gas properties |
|
1,149,540 |
|
|
1,167,367 |
|
|
1,160,518 |
|
Derivative instruments |
|
221 |
|
|
— |
|
|
2,199 |
|
Other
assets |
|
411 |
|
|
389 |
|
|
425 |
|
Total assets |
$ |
1,291,216 |
|
$ |
1,302,664 |
|
$ |
1,340,669 |
|
Liabilities and stockholders’ equity |
|
|
|
Current liabilities: |
|
|
|
Accounts payable and accrued liabilities |
$ |
73,770 |
|
$ |
97,404 |
|
$ |
73,779 |
|
Accrued payroll and benefits payable |
|
7,807 |
|
|
6,420 |
|
|
10,976 |
|
Accrued interest payable |
|
12,207 |
|
|
5,934 |
|
|
13,359 |
|
Revenue distribution payable |
|
26,825 |
|
|
20,714 |
|
|
26,225 |
|
Long-term debt and capital leases, classified as current |
|
11,502 |
|
|
11,854 |
|
|
12,371 |
|
Derivative instruments |
|
4,802 |
|
|
10,874 |
|
|
— |
|
Total
current liabilities |
|
136,913 |
|
|
153,200 |
|
|
136,710 |
|
Long-term
debt and capital leases, less current maturities |
|
382,295 |
|
|
326,198 |
|
|
295,100 |
|
Derivative instruments |
|
9,196 |
|
|
15,976 |
|
|
1,542 |
|
Noncurrent operating lease obligations |
|
2,075 |
|
|
2,307 |
|
|
— |
|
Deferred
compensation |
|
693 |
|
|
628 |
|
|
540 |
|
Asset
retirement obligations |
|
22,300 |
|
|
22,248 |
|
|
22,090 |
|
Commitments and contingencies (Note 10) |
|
|
|
Stockholders’ equity: |
|
|
|
Preferred stock |
|
|
— |
|
|
— |
|
Common stock |
|
469 |
|
|
467 |
|
|
467 |
|
Additional paid in capital |
|
977,611 |
|
|
976,039 |
|
|
974,616 |
|
Treasury stock |
|
(6,107 |
) |
|
(5,399 |
) |
|
(4,936 |
) |
Accumulated deficit |
|
(234,229 |
) |
|
(189,000 |
) |
|
(85,460 |
) |
Total
stockholders' equity |
|
737,744 |
|
|
782,107 |
|
|
884,687 |
|
Total
liabilities and stockholders'
equity |
$ |
1,291,216 |
|
$ |
1,302,664 |
|
$ |
1,340,669 |
|
Consolidated Statements
of Cash Flows (Unaudited) |
|
|
|
|
|
(in thousands) |
Three Months Ended |
Six Months Ended |
|
|
June 30, 2019 |
|
March 31, 2019 |
June 30, 2018 |
June 30, 2019 |
June 30, 2018 |
Cash
flows from operating activities |
|
|
|
|
|
Net
(loss) income: |
$ |
(45,229 |
) |
$ |
(103,540 |
) |
$ |
(21,993 |
) |
$ |
(148,769 |
) |
$ |
(33,435 |
) |
Adjustments to reconcile net (loss) income to net cash
provided by operating activities |
|
|
|
|
|
Depreciation, depletion and amortization |
|
30,282 |
|
|
23,715 |
|
|
20,407 |
|
|
53,997 |
|
|
41,513 |
|
Loss on impairment of oil and gas assets |
|
63,593 |
|
|
49,722 |
|
|
— |
|
|
113,315 |
|
|
— |
|
Loss on impairment of other assets |
|
6,407 |
|
|
— |
|
|
— |
|
|
6,407 |
|
|
— |
|
Derivative (gains) losses |
|
(17,734 |
) |
|
51,016 |
|
|
32,286 |
|
|
33,282 |
|
|
48,787 |
|
(Gain) loss on sale of assets |
|
(491 |
) |
|
1 |
|
|
(469 |
) |
|
(490 |
) |
|
575 |
|
Other |
|
1,079 |
|
|
542 |
|
|
1,948 |
|
|
1,621 |
|
|
3,578 |
|
Change in assets and liabilities |
|
|
|
|
|
Accounts receivable |
|
5,674 |
|
|
7,910 |
|
|
4,480 |
|
|
13,584 |
|
|
(7,660 |
) |
Inventories |
|
(167 |
) |
|
207 |
|
|
6 |
|
|
40 |
|
|
(3,162 |
) |
Prepaid expenses and other assets |
|
799 |
|
|
256 |
|
|
465 |
|
|
1,055 |
|
|
286 |
|
Accounts payable and accrued liabilities |
|
(1,700 |
) |
|
(16,689 |
) |
|
5,607 |
|
|
(18,389 |
) |
|
(4,221 |
) |
Revenue distribution payable |
|
6,111 |
|
|
(5,511 |
) |
|
5,092 |
|
|
600 |
|
|
7,243 |
|
Deferred compensation |
|
927 |
|
|
925 |
|
|
1,865 |
|
|
1,852 |
|
|
6,566 |
|
Net cash provided by operating
activities |
|
49,551 |
|
|
8,554 |
|
|
49,694 |
|
|
58,105 |
|
|
60,070 |
|
Cash flows from investing activities |
|
|
|
|
|
Expenditures for property, plant and equipment and oil and
natural gas properties |
|
(82,390 |
) |
|
(64,044 |
) |
|
(76,334 |
) |
|
(146,434 |
) |
|
(176,275 |
) |
Proceeds from asset dispositions |
|
857 |
|
|
— |
|
|
6,518 |
|
|
857 |
|
|
6,591 |
|
(Payments) proceeds from derivative instruments, net |
|
138 |
|
|
515 |
|
|
(5,525 |
) |
|
653 |
|
|
(9,769 |
) |
Net cash used in investing
activities |
|
(81,395 |
) |
|
(63,529 |
) |
|
(75,341 |
) |
|
(144,924 |
) |
|
(179,453 |
) |
Cash flows from financing activities |
|
|
|
|
|
Proceeds from long-term debt |
|
55,000 |
|
|
30,000 |
|
|
37,000 |
|
|
85,000 |
|
|
116,000 |
|
Repayment of long-term debt |
|
(172 |
) |
|
(171 |
) |
|
(243,245 |
) |
|
(343 |
) |
|
(243,391 |
) |
Proceeds from senior notes |
|
— |
|
|
— |
|
|
300,000 |
|
|
— |
|
|
300,000 |
|
Principal payments under capital lease obligations |
|
(746 |
) |
|
(699 |
) |
|
(668 |
) |
|
(1,445 |
) |
|
(1,329 |
) |
Payment of debt issuance costs and other financing fees |
|
— |
|
|
(20 |
) |
|
(6,316 |
) |
|
(20 |
) |
|
(6,316 |
) |
Treasury stock purchased |
|
(708 |
) |
|
(463 |
) |
|
(4,872 |
) |
|
(1,171 |
) |
|
(4,872 |
) |
Net cash provided by financing
activities |
|
53,374 |
|
|
28,647 |
|
|
81,899 |
|
|
82,021 |
|
|
160,092 |
|
Net increase (decrease) in cash, cash equivalents and
restricted cash |
|
21,530 |
|
|
(26,328 |
) |
|
56,252 |
|
|
(4,798 |
) |
|
40,709 |
|
Cash,
cash equivalents and restricted cash at beginning of period |
|
11,118 |
|
|
37,446 |
|
|
12,189 |
|
|
37,446 |
|
|
27,732 |
|
Cash, cash equivalents and restricted cash at end of period |
$ |
32,648 |
|
$ |
11,118 |
|
$ |
68,441 |
|
$ |
32,648 |
|
$ |
68,441 |
|
Non-GAAP Financial Measures and
ReconciliationsAdjusted EBITDA is a Non-GAAP financial
measure and is described and reconciled to net income in the table
“Adjusted EBITDA Reconciliation, NON-GAAP.”
Cash G&A is a non-GAAP financial measure and is described
and reconciled to net income in the table “Cash G&A
Reconciliation, NON-GAAP.”
Adjusted EBITDA Reconciliation, Non-GAAP |
|
|
|
Three Months Ended |
Six Months Ended |
(in
thousands) |
June 30, 2019 |
March 31, 2019 |
June 30, 2018 |
June 30, 2019 |
June 30, 2018 |
Net loss
income |
|
(45,229 |
) |
|
(103,540 |
) |
|
(21,993 |
) |
|
(148,769 |
) |
|
(33,435 |
) |
Interest expense |
|
5,571 |
|
|
4,564 |
|
|
1,739 |
|
|
10,135 |
|
|
3,110 |
|
Income tax expense |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Depreciation, depletion and amortization |
|
30,282 |
|
|
23,715 |
|
|
20,407 |
|
|
53,997 |
|
|
41,513 |
|
Loss on impairment of assets |
|
63,593 |
|
|
49,722 |
|
|
— |
|
|
113,315 |
|
|
— |
|
Loss on impairment of other assets |
|
6,407 |
|
|
— |
|
|
— |
|
|
6,407 |
|
|
— |
|
Non-cash change in fair value of derivative
instruments |
|
(17,596 |
) |
|
51,531 |
|
|
26,761 |
|
|
33,935 |
|
|
39,018 |
|
Impact of derivative repricing |
|
— |
|
|
— |
|
|
(1,680 |
) |
|
— |
|
|
(2,252 |
) |
Loss on settlement of liabilities subject to
compromise |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
48 |
|
Interest income |
|
(2 |
) |
|
— |
|
|
(1 |
) |
|
(2 |
) |
|
(2 |
) |
Stock-based compensation expense |
|
852 |
|
|
802 |
|
|
1,671 |
|
|
1,654 |
|
|
6,294 |
|
(Gain) loss on sale of assets |
|
(491 |
) |
|
1 |
|
|
(469 |
) |
|
(490 |
) |
|
575 |
|
Restructuring, reorganization and other |
|
313 |
|
|
1,520 |
|
|
480 |
|
|
1,833 |
|
|
1,469 |
|
Adjusted EBITDA |
$ |
43,700 |
|
$ |
28,315 |
|
$ |
26,915 |
|
$ |
72,015 |
|
$ |
56,338 |
|
Cash G&A Reconciliation, Non-GAAP |
|
|
Three Months Ended |
Six Months Ended |
(in
thousands) |
June 30, 2019 |
March 31, 2019 |
June 30, 2018 |
June 30, 2019 |
June 30, 2018 |
General
and administrative |
|
7,315 |
|
|
8,313 |
|
|
8,190 |
|
|
15,628 |
|
|
19,697 |
|
Less: |
|
|
|
|
|
Stock compensation, gross |
|
1,228 |
|
|
1,419 |
|
|
2,335 |
|
|
2,647 |
|
|
7,915 |
|
Capitalized stock compensation |
|
(399 |
) |
|
(626 |
) |
|
(664 |
) |
|
(1,025 |
) |
|
(1,621 |
) |
Officer severance costs |
|
— |
|
|
1,058 |
|
|
— |
|
|
1,058 |
|
|
— |
|
Plus: |
|
|
|
|
|
Cash-settled RSUs, net |
|
5 |
|
|
22 |
|
|
— |
|
|
27 |
|
|
— |
|
Cash
G&A |
$ |
6,491 |
|
$ |
6,484 |
|
$ |
6,519 |
|
$ |
12,975 |
|
$ |
13,403 |
|
|
|
|
|
|
|
Production volumes (MBoe) |
|
2,574 |
|
|
1,874 |
|
|
1,795 |
|
|
4,448 |
|
|
3,532 |
|
|
|
|
|
|
|
Cash G&A per Boe |
$ |
2.52 |
|
$ |
3.46 |
|
$ |
3.63 |
|
$ |
2.92 |
|
$ |
3.79 |
|
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