Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company")
today announced its fourth-quarter and full-year 2020 financial and
operating results.
Full-Year 2020 Highlights
- Fully transitioned development operations to Howard County
acreage and successfully completed the Company's first well
package
- Added 4,000 net acres in Howard County at an average price of
$7,200 per net undeveloped acre
- Produced an average of 87,750 barrels of oil equivalent ("BOE")
per day and 26,849 barrels of oil per day ("BOPD"), an increase of
8% and a decrease of 6%, respectively, from full-year 2019, while
reducing capital expenditures by 27% over the same period
- Reduced drilling and completions costs during the year by 21%,
to $540 per foot from $680 per foot
- Reduced unit lease operating expenses ("LOE") by 17% from
full-year 2019
- Reduced unit general and administrative expenses ("G&A"),
excluding long-term incentive plan expenses ("LTIP"), by 21% from
full-year 2019
- Reduced volume of flared/vented natural gas by 58% from
full-year 2019, flaring/venting only 0.71% of the Company's
produced natural gas during full-year 2020
- Received $234.1 million from settlements of matured/terminated
derivatives
- Extended all term-debt maturities to 2025 and 2028 and
repurchased $61 million of term-debt in open market purchases for
62.5% of par
"Despite the unprecedented challenges of COVID and
the resulting energy demand and commodity price weakness during
2020, the Laredo team adapted to working remotely and executed on
the transformational strategy we communicated in November 2019,"
stated Jason Pigott, President and Chief Executive Officer. "We
continued to deliver by driving down drilling and completions
costs, reducing both unit LOE and G&A expenses, adding
additional acreage in Howard County and managing financial risk by
extending our term-debt maturities and maintaining a robust
commodity hedging program."
Full-Year 2021 Outlook and
Highlights
- 2021 capital budget is expected to generate $25 million to $40
million of Free Cash Flow1 at $52.50 WTI and $2.75 Henry Hub
- 2021 capital budget is expected to maximize capital efficiency
with consistent activity throughout the year, which, combined with
lower costs, results in 25% more completed lateral feet than 2020,
with the same drilling and completions budget
- Focus on oily development in Howard County expected to generate
consistent oil production growth
- Release of the Company's inaugural ESG and Climate Risk Report,
which outlines reduction targets for GHG emissions, methane
emissions and flaring and discloses data in alignment with
Sustainability Accounting Standards Board ("SASB"), the Task Force
on Climate-related Financial Disclosures ("TCFD") and the
International Petroleum Industry Environmental Conservation
Association ("IPIECA") frameworks
"We are very excited about our budgeted plan for
2021," continued Mr. Pigott. "Our first development package in
Howard County continues to perform well and we began completions
operations on our second package in the fourth quarter of 2020.
Focusing our capital in Howard County during 2021 is expected to
result in meaningful capital efficiency gains and Free Cash Flow
generation. We have also released our inaugural ESG and Climate
Risk Report and are pleased to highlight our successes in all ESG
practices and demonstrate our commitment to sustainable development
by setting year-end 2025 GHG intensity, flaring and methane
emission reduction targets. As we move forward with our plan, we
expect the sustainable, highly productive development strategy we
have implemented to create value for all of our stakeholders."
2020 Financial Results
For the fourth quarter of 2020, the Company
reported a net loss attributable to common stockholders of $165.9
million, or $14.18 per diluted share, which includes a non-cash
full cost ceiling impairment charge of $109.8 million. Adjusted Net
Income, a non-GAAP financial measure, for the fourth quarter of
2020 was $37.8 million, or $3.22 per adjusted diluted share.
Adjusted EBITDA, a non-GAAP financial measure, for the fourth
quarter of 2020 was $120.0 million.
For full-year 2020, the Company reported a net
loss attributable to common stockholders of $874.2 million, or
$74.92 per diluted share, which includes a non-cash full cost
ceiling impairment charge of $889.5 million. Adjusted Net Income
for full-year 2020 was $134.3 million, or $11.47 per adjusted
diluted share, and Adjusted EBITDA was $506.9 million.
Please see supplemental financial information at
the end of this release for reconciliations of non-GAAP financial
measures, including calculations of Adjusted EBITDA, Adjusted Net
Income and Free Cash Flow.
Environmental, Social,
Governance
Laredo has consistently demonstrated its
commitment to sustainable development, investing in the
infrastructure and equipment required to minimize the flaring and
venting of produced natural gas and reduce spills of both oil and
water. During 2020, Laredo reduced its flared/vented natural gas
volumes by 58% from full-year 2019, decreasing flared/vented
natural gas as a percentage of produced natural gas from 1.95% in
2019 to 0.71% in 2020. Relatedly, in the second half of 2020, the
Company flared/vented just 0.12% of its produced natural gas,
further demonstrating its position as one of the best operators in
the basin. Additionally, Laredo reduced its oil/water spill rate by
29% during 2020, employing improved monitoring technology to
quicken response times.
Although Laredo's flaring and venting practices
are already among the best in the Permian Basin, the Board
furthered the Company's commitment in 2020 by including
flaring/venting and oil/water spills metrics in the executive
compensation program. These metrics will be further aligned in 2021
with the emission reductions targets announced in our inaugural ESG
and Climate Risk Report.
Laredo is determined to maintain its leadership in
sustainability practices and, accordingly, today released its
inaugural ESG and Climate Risk Report, based on 2019 data. The
Company's disclosures are in alignment with SASB, TCFD and IPIECA
reporting frameworks and highlight Laredo's Board diversity and
women in leadership, as well as the Company's emissions reduction
targets. The Company is proud of its commitment to reduce GHG
intensity by 20%, reduce methane emissions to less than 0.20% of
natural gas production and eliminate routine flaring, all by 2025.
Enhancing this commitment, the Board amended the Nominating and
Corporate Governance Committee charter to include the monitoring
and evaluation of programs and policies relating to ESG matters and
has updated the committee name to the Nominating, Corporate
Governance, Social and Environmental Committee to reflect these
responsibilities.
Additionally, the Company named David Ferris as
Vice President and Chief Sustainability Officer. David will join
Laredo in late February and brings a wealth of operational and ESG
leadership experience. As a consultant, David was instrumental in
the completion of the Company's inaugural ESG and Climate Risk
Report and will be managing future efforts related to the Company's
emissions reduction targets and the implementation of its ESG
strategies.
Operations Summary
In the fourth quarter of 2020, Laredo's total
production averaged 82,552 BOE per day, including oil production of
21,929 BOPD. During the quarter, the Company completed 15 wells,
all in Howard County. Additionally, completions activities on the
Company's second well package were ahead of schedule, as work on
four wells was accelerated into the fourth quarter of 2020 from the
first quarter of 2021.
Laredo's first wells in Howard County, the 15-well
Passow/Gilbert package, are expected to reach peak rates during the
first quarter of 2021 and have a significant impact on
first-quarter 2021 oil production. All wells in the package have
begun producing oil and oil production on the four Lower Spraberry
wells is still increasing. The package maintained average
production of 10,000 gross BOPD for 26 consecutive days prior to
the arrival of the winter storms currently impacting the Permian
Basin.
Extended freezing temperatures and severe icing
have affected the Company's Permian Basin operations for the last
12 days. As always, Laredo's commitment to the safety of its team
members and managing its environmental impact is the Company's
first priority, and Laredo has experienced zero safety incidents
and fluid releases due to the weather.
Multiple challenges, including lack of field gas
and electricity needed for power, shuttered takeaway and processing
capacity, access to well sites and facilities, and inoperable vapor
recovery units necessary for environmental compliance, have impeded
production operations over this 12-day time frame. Additionally,
completions operations were unable to proceed, delaying the
drilling out of plugs on the Company's 12-well Trentino/Whitmire
package in Howard County.
Through the hard work and dedication of our team
members, drilling and completions operations have resumed and
production is returning to pre-storm levels. The Company currently
estimates that the combined impact of shut-in production and
completions delays will reduce first-quarter 2021 total production
by approximately 8,000 BOE per day and oil production by
approximately 3,000 BOPD.
The Company is currently operating two drilling
rigs and one completions crew in Howard County. Laredo expects to
complete 12 wells in Howard County during the first quarter of
2021, although they will be pushed to the end of the quarter due to
weather delays.
2020 Reserves
Laredo grew proved developed reserves by 4% in
2020, an increase of 10.0 million BOE from volumes at year-end
2019. The primary driver of this increase was the shift in
development to Howard County, where the Company booked 7.4 million
BOE (65% oil) of proved developed reserves, representing 10% of
Laredo's proved developed reserves value.
Proved undeveloped reserves ("PUDs") declined by
25.1 million BOE in 2020, primarily as a result of PUD reserves
being converted to proved developed reserves and fewer new PUD
locations being booked in a low commodity price environment. Laredo
has traditionally been conservative in booking PUDs, which now
represent only 9% of proved reserves by volume and 5% by value.
Laredo's proved reserves were valued at $1.01
billion at year-end 2020, based on SEC benchmark pricing of $36.04
for oil and $1.21 for natural gas. The PV-10 value, a non-GAAP
financial measure, of the Company's proved reserves at year-end
2020 was $1.03 billion, of which $971 million was proved developed
reserves. At benchmark prices of $50 WTI and $2.75 Henry Hub,
Laredo estimates the PV-10 value of its year-end 2020 proved
developed reserves to be $1.76 billion.
Expenses
Laredo substantially reduced both operating and
G&A expenses during 2020. Combined unit LOE and G&A,
excluding LTIP, were $3.84 per BOE during 2020, a reduction of 18%
from $4.71 per BOE in 2019.
In 2021, the Company expects unit LOE to increase
from 2020 levels and to average of slightly more than $3.00 per
BOE. Utilization of ESPs for artificial lift in Howard County is
expected to result in higher operating expenses compared to the
Company's established leasehold, but is minimal compared to the
higher margins generated in Howard County.
Total G&A, including LTIP, during 2021 is
expected to remain flat on a total dollar basis as the Company
remains focused on maintaining current staffing levels, but will
likely increase slightly on a unit basis as total production is
expected to be lower versus 2020.
Fourth-Quarter and Full-Year 2020 Costs
Incurred
During the fourth quarter of 2020, total costs
incurred were $76 million, excluding non-budgeted acquisitions,
comprised of $66 million in drilling and completions activities, $1
million in land, exploration and data related costs, $2 million in
infrastructure, including Laredo Midstream Services investments,
and $7 million in other capitalized costs. Costs incurred during
the fourth quarter of 2020 slightly exceeded the high end of
Company expectations due to completions activity that was planned
for first-quarter 2021 being accelerated into fourth-quarter
2020.
Total costs incurred for full-year 2020 were $351
million, a reduction of $131 million from 2019.
2021 Budget and Production
Expectations
The Company's capital program for 2021 is almost
entirely focused on the development of its highly productive Howard
County leasehold. Operations are designed to maximize capital
efficiency by consistently running one completions crew for the
entire year. Continued improvements in drilled and completed feet
per day in the Company's Howard County operations and innovations
such as the Company-owned sand mine are driving additional
productivity gains and higher activity levels, without adding
additional completions crews or drilling rigs.
Laredo expects to invest $360 million in 2021,
excluding non-budgeted acquisitions. The components of the capital
program include $300 million for drilling, completions and
equipment, $30 million for production facilities and equipment and
land, and $30 million for other capitalized items.
The Company expects its 2021 development plan to
result in a significant improvement in overall capital efficiency
with a full-year of operations directed to Howard County. Oil
production for full-year 2021 is expected to average 27,250 -
29,250 BOPD, reduced for weather impact of 750 BOPD, with steady
growth anticipated throughout the year. Total production is
expected to decline to an average of 80,000 - 85,000 BOE per day,
reduced for weather impact of 2,000 BOE per day, as the Company
moves development from its gassier, established acreage position to
its oilier, new acreage position in Howard County.
The 2021 capital plan is supported by a very
robust hedging program, with 78% of expected 2021 oil production
and 68% of expected 2021 total production hedged, based on the
midpoint of guidance. At benchmark pricing of $52.50 WTI and $2.75
Henry Hub, Laredo expects to generate $25 million to $40 million of
Free Cash Flow1. The Company remains committed to maintaining a
consistent development program and plans to utilize Free Cash Flow
to reduce debt.
Please see the table in the appendix of Laredo's
Fourth-Quarter 2020 Earnings Presentation posted to the Company's
website for the full details of the Company's commodity
derivatives.
Liquidity
At December 31, 2020, the Company had outstanding
borrowings of $255 million on its $725 million senior secured
credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $426 million.
Including cash and cash equivalents of $49 million, total liquidity
was $475 million.
At February 22, 2021, the Company had outstanding
borrowings of $250 million on its $725 million senior secured
credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $431 million.
Including cash and cash equivalents of $47 million, total liquidity
was $478 million.
First-Quarter and Full-Year 2021
Guidance
The table below reflects the Company's
first-quarter and full-year guidance for total and oil production
for 2021. Guidance for first-quarter and full-year 2021 adjusts for
recent severe freezing weather in the Permian Basin operating area.
The Company estimates total production and oil production for the
first quarter of 2021 were reduced by 8,000 BOE per day and 3,000
BOPD, respectively, for weather impact. The Company estimates total
production and oil production for full-year 2021 were reduced by
2,000 BOE per day and 750 BOPD, respectively, for weather
impact.
|
|
1Q-21E |
|
FY-21E |
Total
production (MBOE per day) |
|
73.0 - 76.0 |
|
80.0 - 85.0 |
Oil
production (MBOPD) |
|
22.0 -
23.0 |
|
27.3 -
29.3 |
|
|
|
|
|
The table below reflects the Company's guidance
for selected revenue and expense items for the first quarter of
2021. Expense items that are guided to on a unit basis have been
increased by approximately 10% as a result of the 8,000 BOE per day
weather impact to first-quarter 2021 production.
|
|
1Q-21E |
Average
sales price realizations (excluding derivatives): |
|
|
Oil (% of WTI) |
|
|
100 |
% |
NGL (% of WTI) |
|
|
32 |
% |
Natural gas (% of Henry Hub) |
|
|
72 |
% |
|
|
|
Other ($
MM): |
|
|
Net income
(expense) of purchased oil |
|
$ |
(2.6 |
) |
|
|
|
Selected
average costs & expenses: |
|
|
Lease operating expenses ($/BOE) |
|
$ |
3.45 |
|
Production and ad valorem taxes (% of oil, NGL and natural gas
sales revenues) |
|
|
7.00 |
% |
Transportation and marketing expenses ($/BOE) |
|
$ |
1.75 |
|
General and administrative expenses (excluding LTIP, $/BOE) |
|
$ |
1.35 |
|
General and administrative expenses (LTIP cash and non-cash,
$/BOE) |
|
$ |
0.50 |
|
Depletion, depreciation and amortization ($/BOE) |
|
$ |
6.10 |
|
|
|
|
|
|
Conference Call Details
On Tuesday, February 23, 2021, at 7:30 a.m. CT,
Laredo will host a conference call to discuss its fourth-quarter
and full-year 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 7561618, 10 minutes prior to
the scheduled conference time. A telephonic replay will be
available two hours after the call on February 23, 2021 through
Tuesday, March 2, 2021. Participants may access this replay by
dialing 855.859.2056, using conference code 7561618.
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, the impacts of severe weather,
including the freezing of wells and pipelines in the Permian Basin
due to cold weather, 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 the Company's 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, Adjusted Net Income 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.
Laredo Petroleum, Inc.
Selected operating data
|
|
Three months ended December 31, |
|
Years ended December 31, |
|
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Sales
volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,018 |
|
|
2,511 |
|
|
9,827 |
|
|
10,376 |
|
NGL (MBbl) |
|
2,636 |
|
|
2,475 |
|
|
10,615 |
|
|
9,118 |
|
Natural gas (MMcf) |
|
17,648 |
|
|
16,438 |
|
|
70,049 |
|
|
60,169 |
|
Oil equivalents (MBOE)(1)(2) |
|
7,595 |
|
|
7,725 |
|
|
32,117 |
|
|
29,522 |
|
Average daily oil equivalent sales volumes (BOE/D)(2) |
|
82,552 |
|
|
83,968 |
|
|
87,750 |
|
|
80,883 |
|
Average daily oil sales volumes (BOPD)(2) |
|
21,929 |
|
|
27,296 |
|
|
26,849 |
|
|
28,429 |
|
Average
sales prices(2): |
|
|
|
|
|
|
|
|
Oil ($/Bbl)(3) |
|
$ |
41.82 |
|
|
$ |
56.55 |
|
|
$ |
37.43 |
|
|
$ |
55.21 |
|
NGL ($/Bbl)(3) |
|
$ |
10.82 |
|
|
$ |
10.26 |
|
|
$ |
7.37 |
|
|
$ |
11.00 |
|
Natural gas ($/Mcf)(3) |
|
$ |
1.19 |
|
|
$ |
0.74 |
|
|
$ |
0.72 |
|
|
$ |
0.55 |
|
Average sales price ($/BOE)(3) |
|
$ |
17.63 |
|
|
$ |
23.24 |
|
|
$ |
15.45 |
|
|
$ |
23.93 |
|
Oil, with commodity derivatives ($/Bbl)(4) |
|
$ |
60.52 |
|
|
$ |
56.79 |
|
|
$ |
56.41 |
|
|
$ |
54.37 |
|
NGL, with commodity derivatives ($/Bbl)(4) |
|
$ |
11.43 |
|
|
$ |
13.02 |
|
|
$ |
9.12 |
|
|
$ |
13.61 |
|
Natural gas, with commodity derivatives ($/Mcf)(4) |
|
$ |
1.31 |
|
|
$ |
0.94 |
|
|
$ |
1.02 |
|
|
$ |
1.05 |
|
Average sales price, with commodity derivatives ($/BOE)(4) |
|
$ |
23.08 |
|
|
$ |
24.62 |
|
|
$ |
22.50 |
|
|
$ |
25.45 |
|
Selected
average costs and expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
2.57 |
|
|
$ |
2.84 |
|
|
$ |
2.55 |
|
|
$ |
3.08 |
|
Production and ad valorem taxes |
|
1.07 |
|
|
1.43 |
|
|
1.03 |
|
|
1.38 |
|
Transportation and marketing expenses |
|
1.59 |
|
|
1.32 |
|
|
1.55 |
|
|
0.86 |
|
Midstream service expenses |
|
0.09 |
|
|
0.14 |
|
|
0.12 |
|
|
0.15 |
|
General and administrative (excluding LTIP) |
|
1.71 |
|
|
1.37 |
|
|
1.29 |
|
|
1.63 |
|
Total selected operating expenses |
|
$ |
7.03 |
|
|
$ |
7.10 |
|
|
$ |
6.54 |
|
|
$ |
7.10 |
|
General and administrative (LTIP): |
|
|
|
|
|
|
|
|
LTIP cash |
|
$ |
0.12 |
|
|
$ |
— |
|
|
$ |
0.06 |
|
|
$ |
— |
|
LTIP non-cash |
|
$ |
0.25 |
|
|
$ |
0.35 |
|
|
$ |
0.22 |
|
|
$ |
0.22 |
|
Depletion, depreciation and amortization |
|
$ |
5.56 |
|
|
$ |
8.78 |
|
|
$ |
6.76 |
|
|
$ |
9.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________________________________________________________________________
(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 December 31, |
|
Years ended December 31, |
(in thousands, except per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL and natural gas sales |
|
$ |
133,865 |
|
|
$ |
179,558 |
|
|
$ |
496,355 |
|
|
$ |
706,548 |
|
Midstream service revenues |
|
1,534 |
|
|
3,356 |
|
|
8,249 |
|
|
11,928 |
|
Sales of purchased oil |
|
52,666 |
|
|
35,208 |
|
|
172,588 |
|
|
118,805 |
|
Total revenues |
|
188,065 |
|
|
218,122 |
|
|
677,192 |
|
|
837,281 |
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
19,549 |
|
|
21,948 |
|
|
82,020 |
|
|
90,786 |
|
Production and ad valorem taxes |
|
8,115 |
|
|
11,080 |
|
|
33,050 |
|
|
40,712 |
|
Transportation and marketing expenses |
|
12,041 |
|
|
10,164 |
|
|
49,927 |
|
|
25,397 |
|
Midstream service expenses |
|
704 |
|
|
1,085 |
|
|
3,762 |
|
|
4,486 |
|
Costs of purchased oil |
|
56,728 |
|
|
39,034 |
|
|
194,862 |
|
|
122,638 |
|
General and administrative |
|
15,840 |
|
|
13,302 |
|
|
50,534 |
|
|
54,729 |
|
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
4,200 |
|
|
16,371 |
|
Depletion, depreciation and amortization |
|
42,210 |
|
|
67,846 |
|
|
217,101 |
|
|
265,746 |
|
Impairment expense |
|
109,804 |
|
|
222,999 |
|
|
899,039 |
|
|
620,889 |
|
Other operating expenses |
|
1,105 |
|
|
1,041 |
|
|
4,430 |
|
|
4,118 |
|
Total costs and expenses |
|
266,096 |
|
|
388,499 |
|
|
1,538,925 |
|
|
1,245,872 |
|
Operating
loss |
|
(78,031 |
) |
|
(170,377 |
) |
|
(861,733 |
) |
|
(408,591 |
) |
Non-operating income (expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
(81,935 |
) |
|
(57,562 |
) |
|
80,114 |
|
|
79,151 |
|
Interest expense |
|
(26,139 |
) |
|
(15,044 |
) |
|
(105,009 |
) |
|
(61,547 |
) |
Litigation settlement |
|
— |
|
|
— |
|
|
— |
|
|
42,500 |
|
Gain on extinguishment of debt, net |
|
22,309 |
|
|
— |
|
|
8,989 |
|
|
— |
|
Other, net |
|
1,072 |
|
|
(514 |
) |
|
(480 |
) |
|
3,440 |
|
Total non-operating income (expense), net |
|
(84,693 |
) |
|
(73,120 |
) |
|
(16,386 |
) |
|
63,544 |
|
Loss before income taxes |
|
(162,724 |
) |
|
(243,497 |
) |
|
(878,119 |
) |
|
(345,047 |
) |
Income tax
(expense) benefit: |
|
|
|
|
|
|
|
|
Deferred |
|
(3,208 |
) |
|
1,776 |
|
|
3,946 |
|
|
2,588 |
|
Total income tax (expense) benefit |
|
(3,208 |
) |
|
1,776 |
|
|
3,946 |
|
|
2,588 |
|
Net
loss |
|
$ |
(165,932 |
) |
|
$ |
(241,721 |
) |
|
$ |
(874,173 |
) |
|
$ |
(342,459 |
) |
Net loss per
common share(1): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(14.18 |
) |
|
$ |
(20.86 |
) |
|
$ |
(74.92 |
) |
|
$ |
(29.61 |
) |
Diluted |
|
$ |
(14.18 |
) |
|
$ |
(20.86 |
) |
|
$ |
(74.92 |
) |
|
$ |
(29.61 |
) |
Weighted-average common shares outstanding(1): |
|
|
|
|
|
|
|
|
Basic |
|
11,702 |
|
|
11,586 |
|
|
11,668 |
|
|
11,565 |
|
Diluted |
|
11,702 |
|
|
11,586 |
|
|
11,668 |
|
|
11,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________________________________________________________________________
(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 December 31, |
|
Years ended December 31, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows
from operating activities: |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(165,932 |
) |
|
$ |
(241,721 |
) |
|
$ |
(874,173 |
) |
|
$ |
(342,459 |
) |
Adjustments to reconcile net loss to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
2,106 |
|
|
3,046 |
|
|
8,217 |
|
|
8,290 |
|
Depletion, depreciation and amortization |
|
42,210 |
|
|
67,846 |
|
|
217,101 |
|
|
265,746 |
|
Impairment expense |
|
109,804 |
|
|
222,999 |
|
|
899,039 |
|
|
620,889 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
81,935 |
|
|
57,562 |
|
|
(80,114 |
) |
|
(79,151 |
) |
Settlements received for matured derivatives, net |
|
41,786 |
|
|
14,394 |
|
|
228,221 |
|
|
63,221 |
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
— |
|
|
— |
|
|
6,340 |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives |
|
— |
|
|
(1,399 |
) |
|
(51,070 |
) |
|
(9,063 |
) |
Gain on extinguishment of debt, net |
|
(22,309 |
) |
|
— |
|
|
(8,989 |
) |
|
— |
|
Deferred income tax expense (benefit) |
|
3,208 |
|
|
(1,776 |
) |
|
(3,946 |
) |
|
(2,588 |
) |
Other, net |
|
4,767 |
|
|
6,996 |
|
|
22,723 |
|
|
21,791 |
|
Cash flows from operating activities before changes in operating
assets and liabilities, net |
|
97,575 |
|
|
127,947 |
|
|
363,349 |
|
|
541,267 |
|
Change in current assets and liabilities, net |
|
17,601 |
|
|
(15,818 |
) |
|
36,699 |
|
|
(64,123 |
) |
Change in noncurrent assets and liabilities, net |
|
(5,406 |
) |
|
(3,923 |
) |
|
(16,658 |
) |
|
(2,070 |
) |
Net cash provided by operating activities |
|
109,770 |
|
|
108,206 |
|
|
383,390 |
|
|
475,074 |
|
Cash flows
from investing activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties |
|
(12,223 |
) |
|
(196,404 |
) |
|
(35,786 |
) |
|
(199,284 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(69,082 |
) |
|
(90,803 |
) |
|
(347,359 |
) |
|
(458,985 |
) |
Midstream service assets |
|
(654 |
) |
|
(1,169 |
) |
|
(3,171 |
) |
|
(7,910 |
) |
Other fixed assets |
|
(1,235 |
) |
|
(713 |
) |
|
(4,259 |
) |
|
(2,433 |
) |
Proceeds from dispositions of capital assets, net of selling
costs |
|
95 |
|
|
54 |
|
|
1,337 |
|
|
6,901 |
|
Net cash used in investing activities |
|
(83,099 |
) |
|
(289,035 |
) |
|
(389,238 |
) |
|
(661,711 |
) |
Cash flows
from financing activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
35,000 |
|
|
195,000 |
|
|
80,000 |
|
|
275,000 |
|
Payments on Senior Secured Credit Facility |
|
(15,000 |
) |
|
(5,000 |
) |
|
(200,000 |
) |
|
(90,000 |
) |
Issuance of January 2025 Notes and January 2028 Notes |
|
— |
|
|
— |
|
|
1,000,000 |
|
|
— |
|
Extinguishment of debt |
|
(38,139 |
) |
|
— |
|
|
(846,994 |
) |
|
— |
|
Payments for debt issuance costs |
|
(28 |
) |
|
— |
|
|
(18,479 |
) |
|
— |
|
Other, net |
|
(5 |
) |
|
(7 |
) |
|
(779 |
) |
|
(2,657 |
) |
Net cash (used in) provided by financing activities |
|
(18,172 |
) |
|
189,993 |
|
|
13,748 |
|
|
182,343 |
|
Net increase
(decrease) in cash and cash equivalents |
|
8,499 |
|
|
9,164 |
|
|
7,900 |
|
|
(4,294 |
) |
Cash and
cash equivalents, beginning of period |
|
40,258 |
|
|
31,693 |
|
|
40,857 |
|
|
45,151 |
|
Cash and
cash equivalents, end of period |
|
$ |
48,757 |
|
|
$ |
40,857 |
|
|
$ |
48,757 |
|
|
$ |
40,857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 December 31, |
|
Years ended December 31, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas properties |
|
$ |
74,223 |
|
|
$ |
104,616 |
|
|
$ |
344,160 |
|
|
$ |
470,455 |
|
Midstream
service assets |
|
288 |
|
|
1,071 |
|
|
2,985 |
|
|
8,655 |
|
Other fixed
assets |
|
1,056 |
|
|
504 |
|
|
4,148 |
|
|
2,470 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
75,567 |
|
|
$ |
106,191 |
|
|
$ |
351,293 |
|
|
$ |
481,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
1Free Cash Flow
(Unaudited)
Free Cash Flow is a non-GAAP financial measure
that the Company defines as net cash provided by operating
activities (GAAP) before changes in operating assets and
liabilities, net, less costs incurred, excluding non-budgeted
acquisition costs. Free Cash Flow 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 its 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 Company does not provide guidance on the
reconciling items between forecasted net cash provided by operating
activities and forecasted Free Cash Flow due to the uncertainty
regarding timing and estimates of these items. Laredo provides a
range for the forecasts of net cash provided by operating
activities and Free Cash Flow to allow for the variability in
timing and uncertainty of estimates of reconciling items between
forecasted net cash provided by operating activities and forecasted
Free Cash Flow. Therefore, the Company cannot reconcile forecasted
net cash provided by operating activities to forecasted Free Cash
Flow without unreasonable effort.
The following table presents a reconciliation of
net cash provided by operating activities (GAAP) to Free Cash Flow
(non-GAAP) for the periods presented:
|
|
Three months ended December 31, |
|
Years ended December 31, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating activities |
|
$ |
109,770 |
|
|
$ |
108,206 |
|
|
$ |
383,390 |
|
|
$ |
475,074 |
|
Less: |
|
|
|
|
|
|
|
|
Change in current assets and liabilities, net |
|
17,601 |
|
|
(15,818 |
) |
|
36,699 |
|
|
(64,123 |
) |
Change in noncurrent assets and liabilities, net |
|
(5,406 |
) |
|
(3,923 |
) |
|
(16,658 |
) |
|
(2,070 |
) |
Cash flows
from operating activities before changes in operating assets and
liabilities, net |
|
97,575 |
|
|
127,947 |
|
|
363,349 |
|
|
541,267 |
|
Less costs incurred, excluding non-budgeted acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas properties(1) |
|
$ |
74,223 |
|
|
$ |
104,616 |
|
|
$ |
344,160 |
|
|
$ |
470,455 |
|
Midstream service assets(1) |
|
288 |
|
|
1,071 |
|
|
2,985 |
|
|
8,655 |
|
Other fixed assets |
|
1,056 |
|
|
504 |
|
|
4,148 |
|
|
2,470 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
75,567 |
|
|
$ |
106,191 |
|
|
$ |
351,293 |
|
|
$ |
481,580 |
|
Free Cash
Flow (non-GAAP) |
|
$ |
22,008 |
|
|
$ |
21,756 |
|
|
$ |
12,056 |
|
|
$ |
59,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________________________________________________________________________
(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.
Management 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)
for the periods presented:
|
|
Three months ended December 31, |
|
Years ended December 31, |
(in thousands, except per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Loss before income taxes |
|
$ |
(162,724 |
) |
|
$ |
(243,497 |
) |
|
$ |
(878,119 |
) |
|
$ |
(345,047 |
) |
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
81,935 |
|
|
57,562 |
|
|
(80,114 |
) |
|
(79,151 |
) |
Settlements received for matured derivatives, net |
|
41,786 |
|
|
14,394 |
|
|
228,221 |
|
|
63,221 |
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
— |
|
|
— |
|
|
6,340 |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
(1,399 |
) |
|
(477 |
) |
|
(9,063 |
) |
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
4,200 |
|
|
16,371 |
|
Impairment expense |
|
109,804 |
|
|
222,999 |
|
|
899,039 |
|
|
620,889 |
|
Gain on extinguishment of debt, net |
|
(22,309 |
) |
|
— |
|
|
(8,989 |
) |
|
— |
|
Litigation settlement |
|
— |
|
|
— |
|
|
— |
|
|
(42,500 |
) |
(Gain) loss on disposal of assets, net |
|
(94 |
) |
|
(67 |
) |
|
963 |
|
|
248 |
|
Write-off of debt issuance costs |
|
— |
|
|
935 |
|
|
1,103 |
|
|
935 |
|
Adjusted income before adjusted income tax expense |
|
48,398 |
|
|
50,927 |
|
|
172,167 |
|
|
220,494 |
|
Adjusted income tax expense(2) |
|
(10,648 |
) |
|
(11,204 |
) |
|
(37,877 |
) |
|
(48,509 |
) |
Adjusted Net Income (non-GAAP) |
|
$ |
37,750 |
|
|
$ |
39,723 |
|
|
$ |
134,290 |
|
|
$ |
171,985 |
|
Net loss per
common share(3): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(14.18 |
) |
|
$ |
(20.86 |
) |
|
$ |
(74.92 |
) |
|
$ |
(29.61 |
) |
Diluted |
|
$ |
(14.18 |
) |
|
$ |
(20.86 |
) |
|
$ |
(74.92 |
) |
|
$ |
(29.61 |
) |
Adjusted Net
Income per common share(3): |
|
|
|
|
|
|
|
|
Basic |
|
$ |
3.23 |
|
|
$ |
3.43 |
|
|
$ |
11.51 |
|
|
$ |
14.87 |
|
Diluted |
|
$ |
3.23 |
|
|
$ |
3.43 |
|
|
$ |
11.51 |
|
|
$ |
14.87 |
|
Adjusted diluted |
|
$ |
3.22 |
|
|
$ |
3.43 |
|
|
$ |
11.47 |
|
|
$ |
14.83 |
|
Weighted-average common shares outstanding(3): |
|
|
|
|
|
|
|
|
Basic |
|
11,702 |
|
|
11,586 |
|
|
11,668 |
|
|
11,565 |
|
Diluted |
|
11,702 |
|
|
11,586 |
|
|
11,668 |
|
|
11,565 |
|
Adjusted diluted |
|
11,709 |
|
|
11,591 |
|
|
11,712 |
|
|
11,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_______________________________________________________________________________
(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
December 31, 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 December 31, |
|
Years ended December 31, |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net loss |
|
$ |
(165,932 |
) |
|
$ |
(241,721 |
) |
|
$ |
(874,173 |
) |
|
$ |
(342,459 |
) |
Plus: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
2,106 |
|
|
3,046 |
|
|
8,217 |
|
|
8,290 |
|
Depletion, depreciation and amortization |
|
42,210 |
|
|
67,846 |
|
|
217,101 |
|
|
265,746 |
|
Impairment expense |
|
109,804 |
|
|
222,999 |
|
|
899,039 |
|
|
620,889 |
|
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
4,200 |
|
|
16,371 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
81,935 |
|
|
57,562 |
|
|
(80,114 |
) |
|
(79,151 |
) |
Settlements received for matured derivatives, net |
|
41,786 |
|
|
14,394 |
|
|
228,221 |
|
|
63,221 |
|
Settlements received (paid) for early-terminated commodity
derivatives, net |
|
— |
|
|
— |
|
|
6,340 |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
(1,399 |
) |
|
(477 |
) |
|
(9,063 |
) |
Accretion expense |
|
1,105 |
|
|
1,041 |
|
|
4,430 |
|
|
4,118 |
|
(Gain) loss on disposal of assets, net |
|
(94 |
) |
|
(67 |
) |
|
963 |
|
|
248 |
|
Interest expense |
|
26,139 |
|
|
15,044 |
|
|
105,009 |
|
|
61,547 |
|
Gain on extinguishment of debt, net |
|
(22,309 |
) |
|
— |
|
|
(8,989 |
) |
|
— |
|
Litigation settlement |
|
— |
|
|
— |
|
|
— |
|
|
(42,500 |
) |
Write-off of debt issuance costs |
|
— |
|
|
935 |
|
|
1,103 |
|
|
935 |
|
Income tax expense (benefit) |
|
3,208 |
|
|
(1,776 |
) |
|
(3,946 |
) |
|
(2,588 |
) |
Adjusted EBITDA (non-GAAP) |
|
$ |
119,958 |
|
|
$ |
137,904 |
|
|
$ |
506,924 |
|
|
$ |
560,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________________________________________________________________________
(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.
PV-10 (Unaudited) PV-10 is a
non-GAAP financial measure that is derived from the standardized
measure of discounted future net cash flows, which is the most
directly comparable GAAP financial measure. PV-10 is a computation
of the standardized measure of discounted future net cash flows on
a pre-tax basis. PV-10 is equal to the standardized measure of
discounted future net cash flows at the applicable date, before
deducting future income taxes, discounted at 10 percent. Management
believes that the presentation of PV-10 is relevant and useful to
investors because it presents the discounted future net cash flows
attributable to the Company's estimated proved reserves prior to
taking into account future corporate income taxes, and it is a
useful measure for evaluating the relative monetary significance of
the Company's proved oil, NGL and natural gas assets. Further,
investors may utilize the measure as a basis for comparison of the
relative size and value of proved reserves to other companies. The
Company uses this measure when assessing the potential return on
investment related to proved oil, NGL and natural gas assets.
However, PV-10 is not a substitute for the standardized measure of
discounted future net cash flows. The PV-10 measure and the
standardized measure of discounted future net cash flows do not
purport to present the fair value of the Company's oil, NGL and
natural gas reserves of the property.
(in millions) |
|
|
December 31, 2020 |
Standardized measure of discounted future net cash flows |
|
|
$ |
1,015 |
|
Less present
value of future income taxes discounted at 10% |
|
|
(11 |
) |
PV-10
(non-GAAP) |
|
|
$ |
1,026 |
|
|
|
|
|
|
|
Investor Contact: Ron Hagood
918.858.5504 rhagood@laredopetro.com
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