Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its third-quarter 2020 results. For the third
quarter of 2020, the Company reported a net loss attributable to
common stockholders of $237.4 million, or $20.32 per diluted share.
Adjusted Net Income, a non-GAAP financial measure, for the third
quarter of 2020 was $47.0 million, or $4.02 per adjusted diluted
share. Adjusted EBITDA, a non-GAAP financial measure, for the third
quarter of 2020 was $137.3 million.
Please see supplemental financial information at
the end of this news release for reconciliations of non-GAAP
financial measures, including a calculation of Adjusted EBITDA,
Adjusted Net Income and Free Cash Flow.
Third-Quarter 2020 Highlights
- Generated Free Cash Flow, a non-GAAP financial measure, of $71
million and reduced net debt, a non-GAAP financial measure, by $64
million during third-quarter 2020
- Received $58.2 million from settlements of matured/terminated
commodity derivatives, resulting in an average hedged sales price
of $22.76 per barrel of oil equivalent ("BOE"), a 39% increase
versus an average unhedged sales price of $16.39 per BOE in the
same period
- Added 6,800 barrels of oil per day ("BOPD") of 2021 oil hedges
at a weighted-average swap price of $45.55 Brent, increasing 2021
oil hedges to 22,150 BOPD, equivalent to 80% of anticipated 2021
oil production
- Lowered lease operating expenses ("LOE") to $2.45 per BOE, an
18% decrease from third-quarter 2019
- Reduced general and administrative expenses ("G&A"),
excluding long-term incentive plan ("LTIP"), to $1.16 per BOE, a
21% decrease from third-quarter 2019
- Produced an average of 25,120 BOPD and total production of
87,857 BOE per day, a decrease of 10% and an increase of 7%,
respectively, from third-quarter 2019, while reducing drilling and
completions capital expenditures by 54% during the same period
"Since launching our revised strategy a year ago,
the Laredo team has delivered on our core objectives of operational
excellence, financial risk management and inventory expansion, and
this quarter was no exception," commented Jason Pigott, President
and Chief Executive Officer. "We began completions operations in
Howard County and did not miss a beat operationally, continuing our
exemplary run of efficiency gains and proving we can maintain our
low drilling and completions costs in a new area. We generated $71
million in Free Cash Flow, supported by our robust hedge position,
enabling us to reduce debt and increase liquidity, and added more
hedges in 2021 to further protect future cash flows. We have also
increased fourth-quarter and full-year 2020 oil and total
production guidance while maintaining our full-year capital
expenditure guidance as our base production continued to outperform
expectations during the third quarter."
"In October, we closed on a bolt-on transaction in
Howard County, lengthening our runway of higher-margin development
opportunities, and our bank group reaffirmed our $725 million
borrowing base," continued Mr. Pigott. "We have built tremendous
momentum in our business that we expect to carry into 2021 as we
bring on our first package of wells in Howard County, execute a
continuous development plan within cash flow and focus on further
expanding our inventory of high-return locations in Howard
County."
Operations Summary
During third-quarter 2020, Laredo resumed
completions operations, deploying a completions crew in Howard
County. The crew is currently operating on a 15-well package that
is expected to be fully online in early December. To date, the
transition of the Company's operations to Howard County has
exceeded expectations as both drilling and completions efficiencies
have set Company records and well costs are tracking to initial
estimates of $550 per foot.
Laredo produced 87,857 BOE per day in the third
quarter of 2020, including oil production of 25,120 BOPD, with both
figures exceeding the midpoint of guidance. Oil production results
were driven by continued improvement of the Company's first package
of wells on its western Glasscock County acreage, acquired in
December 2019.
The Company is currently operating one drilling
rig and one completions crew, both located in Howard County, and
expects to complete 15 wells during fourth-quarter 2020.
Expenses
Laredo continues to stringently manage cash
expenses, maintaining a peer-leading cost structure. During
third-quarter 2020, the Company reduced combined unit LOE and cash
G&A expenses to $3.61 per BOE, a reduction of 19% from
third-quarter 2019.
Laredo has transitioned to selling almost all of
its production at Gulf Coast pricing, which the Company believes
provides a long-term pricing advantage versus the Midland market.
As such, transportation and marketing expenses, reflecting costs
associated with transporting the Company's produced oil to the US
Gulf Coast and expected deficiency payments related to minimum
transportation volume commitments, increased to $1.63 per BOE in
third-quarter 2020 compared to $0.74 per BOE in third-quarter 2019
as more produced oil was transported to the US Gulf Coast and the
Company expensed anticipated future deficiency payments.
Third-Quarter and Full-Year 2020 Costs
Incurred
During the third quarter of 2020, total costs
incurred were $43 million, comprised of $31 million in drilling and
completions activities, $2 million in land, exploration and data
related costs, $4 million in infrastructure, including Laredo
Midstream Services investments, and $6 million in other capitalized
costs.
Through the first nine months of 2020, excluding
non-budgeted acquisitions, total costs incurred were $276 million.
The Company expects total costs incurred in the fourth quarter of
2020 to be in a range of $64 to $74 million and remain on track to
be within Laredo's full-year 2020 budget of $340 to $350
million.
Increased Oil Hedges
For the remainder of 2020, Laredo has hedged 2.1
million barrels of oil, with 1.5 million barrels of oil swapped at
a weighted-average price of $59.35 WTI per barrel and 0.6 million
barrels of oil swapped at a weighted-average price of $63.07 Brent
per barrel. For 2021, the Company has hedged 80% of expected oil
production, with 8.1 million barrels of oil at a weighted-average
floor price of $50.80 Brent per barrel.
Please see the table in the appendix of Laredo's
Third-Quarter 2020 Earnings Presentation posted to the Company's
website for the full details of the Company's commodity
derivatives.
Liquidity
At September 30, 2020, the Company had outstanding
borrowings of $235 million on its $725 million senior secured
credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $446 million.
Including cash and cash equivalents of $40 million, total liquidity
was $486 million.
At November 2, 2020, the Company had outstanding
borrowings of $220 million on its $725 million senior secured
credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $461 million.
Including cash and cash equivalents of $28 million, total liquidity
was $489 million.
Fourth-Quarter and Full-Year 2020
Guidance
The table below reflects the Company's increased
fourth-quarter and full-year guidance for total and oil production
for 2020. The increase in total production guidance for
fourth-quarter and full-year 2020 reflects the continued
outperformance versus expectations of natural gas production on the
Company's established acreage position. This represent an 8%
increase at the midpoint from full-year 2020 guidance issued with
first-quarter 2020 results and a 2% increase from full-year 2020
guidance issued with second-quarter 2020 results. The Company
raised the low-end of oil production guidance by 2%, compared to
previous guidance issued with second-quarter 2020 results, for both
fourth-quarter and full-year 2020 as established acreage wells have
continued to perform better than type-curve expectations and the
performance of the five-well Western Glasscock package has
improved. The increase in the high-end of guidance includes the
possibility of the Company's 15-well package in Howard County
beginning to produce oil prior to the end of 2020.
|
|
4Q-20E |
|
FY-20E |
Total
production (MBOE per
day) |
|
82.0 - 84.0 |
|
87.6 - 88.1 |
Oil
production
(MBOPD) |
|
21.0 -
23.0 |
|
26.6 -
27.1 |
|
|
|
|
|
The table below reflects the Company's guidance
for selected revenue and expense items for the fourth quarter of
2020.
|
|
4Q-20E |
Average
sales price realizations (excluding derivatives): |
|
|
Oil (% of WTI) |
|
95% |
|
NGL (% of WTI) |
|
26% |
|
Natural gas (% of Henry
Hub) |
|
49% |
|
|
|
|
Other ($
MM): |
|
|
Net income (expense) of purchased
oil |
|
($4.3) |
|
Net midstream service income
(expense) |
|
$0.75 |
|
|
|
|
Selected
average costs & expenses: |
|
|
Lease operating expenses
($/BOE) |
|
$2.80 |
|
Production and ad valorem taxes (% of oil, NGL and natural gas
sales
revenues) |
|
7.25% |
|
Transportation and marketing expenses
($/BOE) |
|
$1.95 |
|
General and administrative expenses (excluding LTIP,
$/BOE) |
|
$1.25 |
|
General and administrative expenses (LTIP cash and non-cash,
$/BOE) |
|
$0.35 |
|
Depletion, depreciation and amortization
($/BOE) |
|
$6.00 |
|
|
|
|
|
Conference Call Details
On Thursday, November 5, 2020, at 7:30 a.m. CT,
Laredo will host a conference call to discuss its third-quarter
2020 financial and operating results and management's outlook, the
content of which is not part of this earnings release. A slide
presentation providing summary financial and statistical
information that will be discussed on the call will be posted to
the Company's website and available for review. The Company invites
interested parties to listen to the call via the Company's website
at www.laredopetro.com, under the tab for "Investor Relations."
Portfolio managers and analysts who would like to participate on
the call should dial 877.930.8286 (international dial-in
253.336.8309), using conference code 2755456, 10 minutes prior to
the scheduled conference time. A telephonic replay will be
available two hours after the call on November 5, 2020 through
Thursday, November 12, 2020. Participants may access this replay by
dialing 855.859.2056, using conference code 2755456.
About Laredo
Laredo Petroleum, Inc. is an independent energy
company with headquarters in Tulsa, Oklahoma. Laredo's business
strategy is focused on the acquisition, exploration and development
of oil and natural gas properties, primarily in the Permian Basin
of West Texas.
Additional information about Laredo may be found
on its website at www.laredopetro.com.
Forward-Looking Statements This
press release and any oral statements made regarding the contents
of this release, including in the conference call referenced
herein, contain forward-looking statements as defined under Section
27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended. All statements,
other than statements of historical facts, that address activities
that Laredo assumes, plans, expects, believes, intends, projects,
indicates, enables, transforms, estimates or anticipates (and other
similar expressions) will, should or may occur in the future are
forward-looking statements. The forward-looking statements are
based on management’s current belief, based on currently available
information, as to the outcome and timing of future events. General
risks relating to Laredo include, but are not limited to, the
decline in prices of oil, natural gas liquids and natural gas and
the related impact to financial statements as a result of asset
impairments and revisions to reserve estimates, oil production
quotas or other actions that might be imposed by the Organization
of Petroleum Exporting Countries and other producing countries
("OPEC+"), the outbreak of disease, such as the coronavirus
("COVID-19") pandemic, and any related government policies and
actions, changes in domestic and global production, supply and
demand for commodities, including as a result of the COVID-19
pandemic and actions by OPEC+, long-term performance of wells,
drilling and operating risks, the increase in service and supply
costs, tariffs on steel, pipeline transportation and storage
constraints in the Permian Basin, the possibility of production
curtailment, hedging activities, possible impacts of litigation and
regulations, the impact of the Company's transactions, if any, with
its securities from time to time, the impact of new laws and
regulations, including those regarding the use of hydraulic
fracturing, the impact of new environmental, health and safety
requirements applicable to our business activities, the possibility
of the elimination of federal income tax deductions for oil and gas
exploration and development and other factors, including those and
other risks described in its Annual Report on Form 10-K for the
year ended December 31, 2019, Amendment No. 1 to its Quarterly
Report on Form 10-Q for the quarter ended March 31, 2020, its
Quarterly Report on Form 10-Q for the quarter ended June 30, 2020,
its Quarterly Report on Form 10-Q for the quarter ended September
30, 2020 and those set forth from time to time in other filings
with the Securities and Exchange Commission ("SEC"). These
documents are available through Laredo's website at
www.laredopetro.com under the tab "Investor Relations" or through
the SEC's Electronic Data Gathering and Analysis Retrieval System
at www.sec.gov. Any of these factors could cause Laredo's actual
results and plans to differ materially from those in the
forward-looking statements. Therefore, Laredo can give no assurance
that its future results will be as estimated. Any forward-looking
statement speaks only as of the date on which such statement is
made. Laredo does not intend to, and disclaims any obligation to,
correct update or revise any forward-looking statement, whether as
a result of new information, future events or otherwise, except as
required by applicable law.
The SEC generally permits oil and natural gas
companies, in filings made with the SEC, to disclose proved
reserves, which are reserve estimates that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, and certain probable and
possible reserves that meet the SEC's definitions for such terms.
In this press release and the conference call, the Company may use
the terms "resource potential," "resource play," "estimated
ultimate recovery" or "EURs," "type curve" and "standardized
measure," each of which the SEC guidelines restrict from being
included in filings with the SEC without strict compliance with SEC
definitions. These terms refer to the Company’s internal estimates
of unbooked hydrocarbon quantities that may be potentially
discovered through exploratory drilling or recovered with
additional drilling or recovery techniques. "Resource potential" is
used by the Company to refer to the estimated quantities of
hydrocarbons that may be added to proved reserves, largely from a
specified resource play potentially supporting numerous drilling
locations. A "resource play" is a term used by the Company to
describe an accumulation of hydrocarbons known to exist over a
large areal expanse and/or thick vertical section potentially
supporting numerous drilling locations, which, when compared to a
conventional play, typically has a lower geological and/or
commercial development risk. "EURs" are based on the Company’s
previous operating experience in a given area and publicly
available information relating to the operations of producers who
are conducting operations in these areas. Unbooked resource
potential and "EURs" do not constitute reserves within the meaning
of the Society of Petroleum Engineer’s Petroleum Resource
Management System or SEC rules and do not include any proved
reserves. Actual quantities of reserves that may be ultimately
recovered from the Company’s interests may differ substantially
from those presented herein. Factors affecting ultimate recovery
include the scope of the Company’s ongoing drilling program, which
will be directly affected by the availability of capital, decreases
in oil, natural gas liquids and natural gas prices, well spacing,
drilling and production costs, availability and cost of drilling
services and equipment, lease expirations, transportation
constraints, regulatory approvals, negative revisions to reserve
estimates and other factors, as well as actual drilling results,
including geological and mechanical factors affecting recovery
rates. "EURs" from reserves may change significantly as development
of the Company’s core assets provides additional data. In addition,
the Company's production forecasts and expectations for future
periods are dependent upon many assumptions, including estimates of
production decline rates from existing wells and the undertaking
and outcome of future drilling activity, which may be affected by
significant commodity price declines or drilling cost increases.
"Type curve" refers to a production profile of a well, or a
particular category of wells, for a specific play and/or area. The
"standardized measure" of discounted future new cash flows is
calculated in accordance with SEC regulations and a discount rate
of 10%. Actual results may vary considerably and should not be
considered to represent the fair market value of the Company’s
proved reserves. This press release and any accompanying
disclosures include financial measures that are not in accordance
with generally accepted accounting principles ("GAAP"), such as
Adjusted EBITDA, Cash Flow and Free Cash Flow. While management
believes that such measures are useful for investors, they should
not be used as a replacement for financial measures that are in
accordance with GAAP. For a reconciliation of such non-GAAP
financial measures to the nearest comparable measure in accordance
with GAAP, please see the supplemental financial information at the
end of this press release. Unless otherwise specified, references
to "average sales price" refer to average sales price excluding the
effects of the Company's derivative transactions.
All amounts, dollars and percentages presented in
this press release are rounded and therefore approximate.
Net Debt Net Debt, a non-GAAP
financial measure, is calculated as long-term debt less cash.
Management believes Net Debt is useful to management and investors
in determining the Company’s leverage position since the Company
has the ability, and may decide, to use a portion of its cash and
cash equivalents to reduce debt.
Free Cash Flow Free Cash Flow, a
non-GAAP financial measure, represents net cash provided by
operating activities before changes in operating assets and
liabilities, net, less costs incurred, excluding non-budgeted
acquisition costs. Management believes Free Cash Flow is useful to
management and investors in evaluating the operating trends in its
business due to production, commodity prices, operating costs and
other related factors. There are significant limitations to the use
of Free Cash Flow as a measure of performance, including the lack
of comparability due to the different methods of calculating Free
Cash Flow reported by different companies.
Laredo Petroleum, Inc.
Selected operating data
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
|
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Sales
volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,311 |
|
|
2,560 |
|
|
|
7,809 |
|
|
7,865 |
|
NGL (MBbl) |
|
2,760 |
|
|
2,344 |
|
|
|
7,979 |
|
|
6,643 |
|
Natural gas (MMcf) |
|
18,072 |
|
|
15,790 |
|
|
|
52,401 |
|
|
43,731 |
|
Oil equivalents (MBOE)(1)(2) |
|
8,083 |
|
|
7,537 |
|
|
|
24,522 |
|
|
21,797 |
|
Average daily oil equivalent sales volumes (BOE/D)(2) |
|
87,857 |
|
|
81,921 |
|
|
|
89,496 |
|
|
79,843 |
|
Average daily oil sales volumes (BOPD)(2) |
|
25,120 |
|
|
27,830 |
|
|
|
28,500 |
|
|
28,810 |
|
Average
sales prices(2): |
|
|
|
|
|
|
|
|
Oil ($/Bbl)(3) |
|
$ |
40.38 |
|
|
$ |
55.35 |
|
|
|
$ |
36.29 |
|
|
$ |
54.79 |
|
NGL ($/Bbl)(3) |
|
$ |
9.04 |
|
|
$ |
8.75 |
|
|
|
$ |
6.23 |
|
|
$ |
11.28 |
|
Natural gas ($/Mcf)(3) |
|
$ |
0.79 |
|
|
$ |
0.48 |
|
|
|
$ |
0.56 |
|
|
$ |
0.48 |
|
Average sales price ($/BOE)(3) |
|
$ |
16.39 |
|
|
$ |
22.52 |
|
|
|
$ |
14.78 |
|
|
$ |
24.18 |
|
Oil, with commodity derivatives ($/Bbl)(4) |
|
$ |
59.93 |
|
|
$ |
56.15 |
|
|
|
$ |
55.35 |
|
|
$ |
53.59 |
|
NGL, with commodity derivatives ($/Bbl)(4) |
|
$ |
10.46 |
|
|
$ |
13.43 |
|
|
|
$ |
8.35 |
|
|
$ |
13.83 |
|
Natural gas, with commodity derivatives ($/Mcf)(4) |
|
$ |
0.92 |
|
|
$ |
1.01 |
|
|
|
$ |
0.92 |
|
|
$ |
1.09 |
|
Average sales price, with commodity derivatives ($/BOE)(4) |
|
$ |
22.76 |
|
|
$ |
25.38 |
|
|
|
$ |
22.32 |
|
|
$ |
25.75 |
|
Selected
average costs and expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
2.45 |
|
|
$ |
3.00 |
|
|
|
$ |
2.55 |
|
|
$ |
3.16 |
|
Production and ad valorem taxes |
|
1.08 |
|
|
1.47 |
|
|
|
1.02 |
|
|
1.36 |
|
Transportation and marketing expenses |
|
1.63 |
|
|
0.74 |
|
|
|
1.54 |
|
|
0.70 |
|
Midstream service expenses |
|
0.13 |
|
|
0.16 |
|
|
|
0.12 |
|
|
0.16 |
|
General and administrative (excluding LTIP) |
|
1.16 |
|
|
1.46 |
|
|
|
1.16 |
|
|
1.72 |
|
Total selected operating expenses |
|
$ |
6.45 |
|
|
$ |
6.83 |
|
|
|
$ |
6.39 |
|
|
$ |
7.10 |
|
General and administrative (LTIP): |
|
|
|
|
|
|
|
|
LTIP cash |
|
$ |
0.03 |
|
|
$ |
— |
|
|
|
$ |
0.04 |
|
|
$ |
— |
|
LTIP non-cash |
|
$ |
0.23 |
|
|
$ |
(0.28 |
) |
|
|
$ |
0.22 |
|
|
$ |
0.18 |
|
Depletion, depreciation and amortization |
|
$ |
5.82 |
|
|
$ |
9.17 |
|
|
|
$ |
7.13 |
|
|
$ |
9.08 |
|
_______________________________________________________________________________
(1) |
BOE is calculated using a conversion rate of six Mcf per one
Bbl. |
(2) |
The numbers presented are calculated based on actual amounts that
are not rounded. |
(3) |
Price reflects the average of actual sales prices received when
control passes to the purchaser/customer adjusted for quality,
certain transportation fees, geographical differentials, marketing
bonuses or deductions and other factors affecting the price
received at the delivery point. |
(4) |
Price reflects the after-effects of the Company's commodity
derivative transactions on it's average sales prices. The Company's
calculation of such after-effects includes settlements of matured
commodity derivatives during the respective periods in accordance
with GAAP and an adjustment to reflect premiums incurred previously
or upon settlement that are attributable to commodity derivatives
that settled during the respective periods. |
|
|
Laredo Petroleum, Inc.
Condensed consolidated statements of
operations
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands, except per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL and natural gas sales |
|
$ |
132,462 |
|
|
|
$ |
169,751 |
|
|
|
$ |
362,490 |
|
|
|
$ |
526,990 |
|
|
Midstream service revenues |
|
1,751 |
|
|
|
3,079 |
|
|
|
6,715 |
|
|
|
8,572 |
|
|
Sales of purchased oil |
|
39,334 |
|
|
|
20,739 |
|
|
|
119,922 |
|
|
|
83,597 |
|
|
Total revenues |
|
173,547 |
|
|
|
193,569 |
|
|
|
489,127 |
|
|
|
619,159 |
|
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
19,840 |
|
|
|
22,597 |
|
|
|
62,471 |
|
|
|
68,838 |
|
|
Production and ad valorem taxes |
|
8,753 |
|
|
|
11,085 |
|
|
|
24,935 |
|
|
|
29,632 |
|
|
Transportation and marketing expenses |
|
13,161 |
|
|
|
5,583 |
|
|
|
37,886 |
|
|
|
15,233 |
|
|
Midstream service expenses |
|
1,073 |
|
|
|
1,191 |
|
|
|
3,058 |
|
|
|
3,401 |
|
|
Costs of purchased oil |
|
42,720 |
|
|
|
20,741 |
|
|
|
138,134 |
|
|
|
83,604 |
|
|
General and administrative |
|
11,473 |
|
|
|
8,852 |
|
|
|
34,694 |
|
|
|
41,427 |
|
|
Organizational restructuring expenses |
|
— |
|
|
|
5,965 |
|
|
|
4,200 |
|
|
|
16,371 |
|
|
Depletion, depreciation and amortization |
|
47,015 |
|
|
|
69,099 |
|
|
|
174,891 |
|
|
|
197,900 |
|
|
Impairment expense |
|
196,088 |
|
|
|
397,890 |
|
|
|
789,235 |
|
|
|
397,890 |
|
|
Other operating expenses |
|
1,102 |
|
|
|
1,005 |
|
|
|
3,325 |
|
|
|
3,077 |
|
|
Total costs and expenses |
|
341,225 |
|
|
|
544,008 |
|
|
|
1,272,829 |
|
|
|
857,373 |
|
|
Operating
loss |
|
(167,678 |
) |
|
|
(350,439 |
) |
|
|
(783,702 |
) |
|
|
(238,214 |
) |
|
Non-operating income (expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
(45,250 |
) |
|
|
96,684 |
|
|
|
162,049 |
|
|
|
136,713 |
|
|
Interest expense |
|
(26,828 |
) |
|
|
(15,191 |
) |
|
|
(78,870 |
) |
|
|
(46,503 |
) |
|
Litigation settlement |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
42,500 |
|
|
Loss on extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
(13,320 |
) |
|
|
— |
|
|
Other, net |
|
(74 |
) |
|
|
1,850 |
|
|
|
(1,552 |
) |
|
|
3,954 |
|
|
Total non-operating income (expense), net |
|
(72,152 |
) |
|
|
83,343 |
|
|
|
68,307 |
|
|
|
136,664 |
|
|
Loss before income taxes |
|
(239,830 |
) |
|
|
(267,096 |
) |
|
|
(715,395 |
) |
|
|
(101,550 |
) |
|
Income tax
benefit: |
|
|
|
|
|
|
|
|
Deferred |
|
2,398 |
|
|
|
2,467 |
|
|
|
7,154 |
|
|
|
812 |
|
|
Total income tax benefit |
|
2,398 |
|
|
|
2,467 |
|
|
|
7,154 |
|
|
|
812 |
|
|
Net
loss |
|
$ |
(237,432 |
) |
|
|
$ |
(264,629 |
) |
|
|
$ |
(708,241 |
) |
|
|
$ |
(100,738 |
) |
|
Net loss per
common share(1): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(20.32 |
) |
|
|
$ |
(22.86 |
) |
|
|
$ |
(60.76 |
) |
|
|
$ |
(8.72 |
) |
|
Diluted |
|
$ |
(20.32 |
) |
|
|
$ |
(22.86 |
) |
|
|
$ |
(60.76 |
) |
|
|
$ |
(8.72 |
) |
|
Weighted-average common shares outstanding(1): |
|
|
|
|
|
|
|
|
Basic |
|
11,686 |
|
|
|
11,578 |
|
|
|
11,657 |
|
|
|
11,558 |
|
|
Diluted |
|
11,686 |
|
|
|
11,578 |
|
|
|
11,657 |
|
|
|
11,558 |
|
|
_______________________________________________________________________________
(1) |
Net loss per common share and weighted-average common shares
outstanding were retroactively adjusted for the Company's 1-for-20
reverse stock split effective June 1, 2020. |
|
|
Laredo Petroleum, Inc.
Condensed consolidated statements of cash
flows
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows
from operating activities: |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(237,432 |
) |
|
|
$ |
(264,629 |
) |
|
|
$ |
(708,241 |
) |
|
|
$ |
(100,738 |
) |
|
Adjustments to reconcile net loss to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
2,041 |
|
|
|
(1,739 |
) |
|
|
6,111 |
|
|
|
5,244 |
|
|
Depletion, depreciation and amortization |
|
47,015 |
|
|
|
69,099 |
|
|
|
174,891 |
|
|
|
197,900 |
|
|
Impairment expense |
|
196,088 |
|
|
|
397,890 |
|
|
|
789,235 |
|
|
|
397,890 |
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
45,250 |
|
|
|
(96,684 |
) |
|
|
(162,049 |
) |
|
|
(136,713 |
) |
|
Settlements received for matured derivatives, net |
|
51,840 |
|
|
|
25,245 |
|
|
|
186,435 |
|
|
|
48,827 |
|
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
6,340 |
|
|
|
— |
|
|
|
6,340 |
|
|
|
(5,409 |
) |
|
Premiums paid for commodity derivatives |
|
— |
|
|
|
(1,415 |
) |
|
|
(51,070 |
) |
|
|
(7,664 |
) |
|
Loss on extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
13,320 |
|
|
|
— |
|
|
Deferred income tax benefit |
|
(2,398 |
) |
|
|
(2,467 |
) |
|
|
(7,154 |
) |
|
|
(812 |
) |
|
Other, net |
|
5,099 |
|
|
|
2,606 |
|
|
|
17,956 |
|
|
|
14,795 |
|
|
Cash flows from operating activities before changes in operating
assets and liabilities, net |
|
113,843 |
|
|
|
127,906 |
|
|
|
265,774 |
|
|
|
413,320 |
|
|
Change in current assets and liabilities, net |
|
(8,360 |
) |
|
|
(21,183 |
) |
|
|
19,098 |
|
|
|
(48,305 |
) |
|
Change in noncurrent assets and liabilities, net |
|
(3,425 |
) |
|
|
(1,124 |
) |
|
|
(11,252 |
) |
|
|
1,853 |
|
|
Net cash provided by operating activities |
|
102,058 |
|
|
|
105,599 |
|
|
|
273,620 |
|
|
|
366,868 |
|
|
Cash flows
from investing activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties, net |
|
— |
|
|
|
— |
|
|
|
(23,563 |
) |
|
|
(2,880 |
) |
|
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(36,338 |
) |
|
|
(83,566 |
) |
|
|
(278,277 |
) |
|
|
(368,182 |
) |
|
Midstream service assets |
|
(756 |
) |
|
|
(1,292 |
) |
|
|
(2,517 |
) |
|
|
(6,741 |
) |
|
Other fixed assets |
|
(955 |
) |
|
|
(755 |
) |
|
|
(3,024 |
) |
|
|
(1,720 |
) |
|
Proceeds from dispositions of capital assets, net of selling
costs |
|
514 |
|
|
|
5,911 |
|
|
|
1,242 |
|
|
|
6,847 |
|
|
Net cash used in investing activities |
|
(37,535 |
) |
|
|
(79,702 |
) |
|
|
(306,139 |
) |
|
|
(372,676 |
) |
|
Cash flows
from financing activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
45,000 |
|
|
|
— |
|
|
|
45,000 |
|
|
|
80,000 |
|
|
Payments on Senior Secured Credit Facility |
|
(85,000 |
) |
|
|
(50,000 |
) |
|
|
(185,000 |
) |
|
|
(85,000 |
) |
|
Issuance of January 2025 Notes and January 2028 Notes |
|
— |
|
|
|
— |
|
|
|
1,000,000 |
|
|
|
— |
|
|
Extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
(808,855 |
) |
|
|
— |
|
|
Payments for debt issuance costs |
|
— |
|
|
|
— |
|
|
|
(18,451 |
) |
|
|
— |
|
|
Other, net |
|
(12 |
) |
|
|
(4 |
) |
|
|
(774 |
) |
|
|
(2,650 |
) |
|
Net cash (used in) provided by financing activities |
|
(40,012 |
) |
|
|
(50,004 |
) |
|
|
31,920 |
|
|
|
(7,650 |
) |
|
Net increase
(decrease) in cash and cash equivalents |
|
24,511 |
|
|
|
(24,107 |
) |
|
|
(599 |
) |
|
|
(13,458 |
) |
|
Cash and
cash equivalents, beginning of period |
|
15,747 |
|
|
|
55,800 |
|
|
|
40,857 |
|
|
|
45,151 |
|
|
Cash and
cash equivalents, end of period |
|
$ |
40,258 |
|
|
|
$ |
31,693 |
|
|
|
$ |
40,258 |
|
|
|
$ |
31,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum, Inc.
Total Costs Incurred
The following table presents the components of the
Company's costs incurred, excluding non-budgeted acquisition costs,
for the periods presented:
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2020 |
|
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas properties |
|
$ |
41,128 |
|
|
$ |
76,837 |
|
|
$ |
269,937 |
|
|
$ |
365,839 |
|
Midstream
service assets |
|
1,103 |
|
|
1,147 |
|
|
2,697 |
|
|
7,584 |
|
Other fixed
assets |
|
495 |
|
|
999 |
|
|
3,092 |
|
|
1,966 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
42,726 |
|
|
$ |
78,983 |
|
|
$ |
275,726 |
|
|
$ |
375,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial
measures
Non-GAAP financial measures
The non-GAAP financial measures of Free Cash Flow,
Adjusted Net Income and Adjusted EBITDA, as defined by the Company,
may not be comparable to similarly titled measures used by other
companies. Therefore, these non-GAAP financial measures should be
considered in conjunction with net income or loss and other
performance measures prepared in accordance with GAAP, such as
operating income or loss or cash flows from operating activities.
Free Cash Flow, Adjusted Net Income and Adjusted EBITDA should not
be considered in isolation or as a substitute for GAAP measures,
such as net income or loss, operating income or loss or any other
GAAP measure of liquidity or financial performance.
Free Cash Flow (Unaudited)
Free Cash Flow, a non-GAAP financial measure, does
not represent funds available for future discretionary use because
it excludes funds required for future debt service, capital
expenditures, acquisitions, working capital, income taxes,
franchise taxes and other commitments and obligations. However,
management believes Free Cash Flow is useful to management and
investors in evaluating operating trends in the Company's business
that are affected by production, commodity prices, operating costs
and other related factors. There are significant limitations to the
use of Free Cash Flow as a measure of performance, including the
lack of comparability due to the different methods of calculating
Free Cash Flow reported by different companies.
The following table presents a reconciliation of
net cash provided by operating activities (GAAP) to cash flows from
operating activities before changes in operating assets and
liabilities, net, less costs incurred, excluding non-budgeted
acquisition costs, for the calculation of Free Cash Flow (non-GAAP)
for the periods presented:
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating activities |
|
$ |
102,058 |
|
|
|
$ |
105,599 |
|
|
|
$ |
273,620 |
|
|
|
$ |
366,868 |
|
|
Less: |
|
|
|
|
|
|
|
|
Change in current assets and liabilities, net |
|
(8,360 |
) |
|
|
(21,183 |
) |
|
|
19,098 |
|
|
|
(48,305 |
) |
|
Change in noncurrent assets and liabilities, net |
|
(3,425 |
) |
|
|
(1,124 |
) |
|
|
(11,252 |
) |
|
|
1,853 |
|
|
Cash flows
from operating activities before changes in operating assets and
liabilities, net |
|
113,843 |
|
|
|
127,906 |
|
|
|
265,774 |
|
|
|
413,320 |
|
|
Less costs incurred, excluding non-budgeted acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas properties(1) |
|
41,128 |
|
|
|
76,837 |
|
|
|
269,937 |
|
|
|
365,839 |
|
|
Midstream service assets(1) |
|
1,103 |
|
|
|
1,147 |
|
|
|
2,697 |
|
|
|
7,584 |
|
|
Other fixed assets |
|
495 |
|
|
|
999 |
|
|
|
3,092 |
|
|
|
1,966 |
|
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
42,726 |
|
|
|
78,983 |
|
|
|
275,726 |
|
|
|
375,389 |
|
|
Free Cash
Flow (non-GAAP) |
|
$ |
71,117 |
|
|
|
$ |
48,923 |
|
|
|
$ |
(9,952 |
) |
|
|
$ |
37,931 |
|
|
_____________________________________________________________________________
(1) |
Includes capitalized share-settled equity-based compensation and
asset retirement costs. |
|
|
Adjusted Net Income
(Unaudited)
Adjusted Net Income is a non-GAAP financial
measure that the Company defines as income or loss before income
taxes plus adjustments for mark-to-market on derivatives, premiums
paid for commodity derivatives that matured during the period,
impairment expense, gains or losses on disposal of assets, other
non-recurring income and expenses and adjusted income tax expense.
The Company believes Adjusted Net Income helps investors in the oil
and natural gas industry to measure and compare the Company's
performance to other oil and natural gas companies by excluding
from the calculation items that can vary significantly from company
to company depending upon accounting methods, the book value of
assets and other non-operational factors.
The following table presents a reconciliation of
loss before income taxes (GAAP) to Adjusted Net Income
(non-GAAP):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands, except per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Loss before income taxes |
|
$ |
(239,830 |
) |
|
|
$ |
(267,096 |
) |
|
|
$ |
(715,395 |
) |
|
|
$ |
(101,550 |
) |
|
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
45,250 |
|
|
|
(96,684 |
) |
|
|
(162,049 |
) |
|
|
(136,713 |
) |
|
Settlements received for matured derivatives, net |
|
51,840 |
|
|
|
25,245 |
|
|
|
186,435 |
|
|
|
48,827 |
|
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
6,340 |
|
|
|
— |
|
|
|
6,340 |
|
|
|
(5,409 |
) |
|
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
|
(1,415 |
) |
|
|
(477 |
) |
|
|
(7,664 |
) |
|
Organizational restructuring expenses |
|
— |
|
|
|
5,965 |
|
|
|
4,200 |
|
|
|
16,371 |
|
|
Impairment expense |
|
196,088 |
|
|
|
397,890 |
|
|
|
789,235 |
|
|
|
397,890 |
|
|
Loss on extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
13,320 |
|
|
|
— |
|
|
Litigation settlement |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(42,500 |
) |
|
(Gain) loss on disposal of assets, net |
|
607 |
|
|
|
(1,294 |
) |
|
|
1,057 |
|
|
|
315 |
|
|
Write-off of debt issuance costs |
|
— |
|
|
|
— |
|
|
|
1,103 |
|
|
|
— |
|
|
Adjusted income before adjusted income tax expense |
|
60,295 |
|
|
|
62,611 |
|
|
|
123,769 |
|
|
|
169,567 |
|
|
Adjusted income tax expense(2) |
|
(13,265 |
) |
|
|
(13,774 |
) |
|
|
(27,229 |
) |
|
|
(37,305 |
) |
|
Adjusted Net Income |
|
$ |
47,030 |
|
|
|
$ |
48,837 |
|
|
|
$ |
96,540 |
|
|
|
$ |
132,262 |
|
|
Net loss per
common share(3): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(20.32 |
) |
|
|
$ |
(22.86 |
) |
|
|
$ |
(60.76 |
) |
|
|
$ |
(8.72 |
) |
|
Diluted |
|
$ |
(20.32 |
) |
|
|
$ |
(22.86 |
) |
|
|
$ |
(60.76 |
) |
|
|
$ |
(8.72 |
) |
|
Adjusted Net
Income per common share(3): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
4.02 |
|
|
|
$ |
4.22 |
|
|
|
$ |
8.28 |
|
|
|
$ |
11.44 |
|
|
Diluted |
|
$ |
4.02 |
|
|
|
$ |
4.22 |
|
|
|
$ |
8.28 |
|
|
|
$ |
11.44 |
|
|
Adjusted diluted |
|
$ |
4.02 |
|
|
|
$ |
4.22 |
|
|
|
$ |
8.25 |
|
|
|
$ |
11.41 |
|
|
Weighted-average common shares outstanding(3): |
|
|
|
|
|
|
|
|
Basic |
|
11,686 |
|
|
|
11,578 |
|
|
|
11,657 |
|
|
|
11,558 |
|
|
Diluted |
|
11,686 |
|
|
|
11,578 |
|
|
|
11,657 |
|
|
|
11,558 |
|
|
Adjusted diluted |
|
11,691 |
|
|
|
11,585 |
|
|
|
11,705 |
|
|
|
11,587 |
|
|
_______________________________________________________________________________
(1) |
Reflects premiums incurred previously or upon settlement that are
attributable to derivatives settled in the respective periods
presented and were not a result of a hedge restructuring. |
(2) |
Adjusted income tax expense is calculated by applying a statutory
tax rate of 22% for each of the periods ended September 30,
2020 and 2019. |
(3) |
Net loss per common share, Adjusted Net Income per common share and
weighted-average common shares outstanding were retroactively
adjusted for the Company's 1-for-20 reverse stock split effective
June 1, 2020. |
|
|
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure
that the Company defines as net income or loss plus adjustments for
share-settled equity-based compensation, depletion, depreciation
and amortization, impairment expense, mark-to-market on
derivatives, premiums paid for commodity derivatives that matured
during the period, accretion expense, gains or losses on disposal
of assets, interest expense, income taxes and other non-recurring
income and expenses. Adjusted EBITDA provides no information
regarding a company's capital structure, borrowings, interest
costs, capital expenditures, working capital movement or tax
position. Adjusted EBITDA does not represent funds available for
future discretionary use because it excludes funds required for
debt service, capital expenditures, working capital, income taxes,
franchise taxes and other commitments and obligations. However,
management believes Adjusted EBITDA is useful to an investor in
evaluating the Company's operating performance because this
measure:
- is widely used by investors in the oil and natural gas industry
to measure a company's operating performance without regard to
items that can vary substantially from company to company depending
upon accounting methods, the book value of assets, capital
structure and the method by which assets were acquired, among other
factors;
- helps investors to more meaningfully evaluate and compare the
results of the Company's operations from period to period by
removing the effect of its capital structure from its operating
structure; and
- is used by management for various purposes, including as
a measure of operating performance, in presentations to the
Company's board of directors and as a basis for strategic planning
and forecasting.
There are significant limitations to the use of
Adjusted EBITDA as a measure of performance, including the
inability to analyze the effect of certain recurring and
non-recurring items that materially affect the Company's net income
or loss and the lack of comparability of results of operations to
different companies due to the different methods of calculating
Adjusted EBITDA reported by different companies. The Company's
measurements of Adjusted EBITDA for financial reporting as compared
to compliance under its debt agreements differ.
The following table presents a reconciliation of
net loss (GAAP) to Adjusted EBITDA (non-GAAP) for the periods
presented:
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net loss |
|
$ |
(237,432 |
) |
|
|
$ |
(264,629 |
) |
|
|
$ |
(708,241 |
) |
|
|
$ |
(100,738 |
) |
|
Plus: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
2,041 |
|
|
|
(1,739 |
) |
|
|
6,111 |
|
|
|
5,244 |
|
|
Depletion, depreciation and amortization |
|
47,015 |
|
|
|
69,099 |
|
|
|
174,891 |
|
|
|
197,900 |
|
|
Impairment expense |
|
196,088 |
|
|
|
397,890 |
|
|
|
789,235 |
|
|
|
397,890 |
|
|
Organizational restructuring expenses |
|
— |
|
|
|
5,965 |
|
|
|
4,200 |
|
|
|
16,371 |
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
45,250 |
|
|
|
(96,684 |
) |
|
|
(162,049 |
) |
|
|
(136,713 |
) |
|
Settlements received for matured derivatives, net |
|
51,840 |
|
|
|
25,245 |
|
|
|
186,435 |
|
|
|
48,827 |
|
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
6,340 |
|
|
|
— |
|
|
|
6,340 |
|
|
|
(5,409 |
) |
|
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
|
(1,415 |
) |
|
|
(477 |
) |
|
|
(7,664 |
) |
|
Accretion expense |
|
1,102 |
|
|
|
1,005 |
|
|
|
3,325 |
|
|
|
3,077 |
|
|
(Gain) loss on disposal of assets, net |
|
607 |
|
|
|
(1,294 |
) |
|
|
1,057 |
|
|
|
315 |
|
|
Interest expense |
|
26,828 |
|
|
|
15,191 |
|
|
|
78,870 |
|
|
|
46,503 |
|
|
Loss on extinguishment of debt |
|
— |
|
|
|
— |
|
|
|
13,320 |
|
|
|
— |
|
|
Litigation settlement |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(42,500 |
) |
|
Write-off of debt issuance costs |
|
— |
|
|
|
— |
|
|
|
1,103 |
|
|
|
— |
|
|
Income tax benefit |
|
(2,398 |
) |
|
|
(2,467 |
) |
|
|
(7,154 |
) |
|
|
(812 |
) |
|
Adjusted EBITDA |
|
$ |
137,281 |
|
|
|
$ |
146,167 |
|
|
|
$ |
386,966 |
|
|
|
$ |
422,291 |
|
|
_____________________________________________________________________________
(1) |
Reflects premiums incurred previously or upon settlement that are
attributable to derivatives settled in the respective periods
presented and were not a result of a hedge restructuring. |
|
|
Contacts: Ron Hagood: 918.858.5504 -
RHagood@laredopetro.com
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