Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company")
today announced its fourth-quarter and full-year 2021 financial and
operating results. Under a separate press release, the Company
today also issued its 2022 outlook. A conference call and webcast
to discuss the Company's financial and operating results and its
2022 outlook is planned for 7:30 a.m. CT, Wednesday, February, 23,
2022. Complete details can be found within this release.
2021 Highlights
- Grew development inventory through acquisition of ~41,000 net
acres in Howard and western Glasscock counties, adding ~250
high-margin, oil-weighted locations
- Added an additional ~125 oil-weighted locations in the Middle
Spraberry formation in Howard County and the Wolfcamp D formation
in western Glasscock County following recent appraisal success
- Increased average daily oil production by 19% versus full-year
2020
- Increased total proved reserves by 15% in 2021, including a 78%
increase in proved oil reserves. Oil now comprises 38% of total
proved reserves versus 24% at year-end 2020
- Accelerated transition to oil-weighted assets through sale of
~94 million BOE of lower-margin gas-weighted reserves, primarily in
Glasscock and Reagan counties
- Increased liquidity through the sale of 1.4 million shares of
common stock for net proceeds of $72.5 million through the
Company's at-the-market equity program and issuance of $400 million
of senior notes maturing in 2029
- Reduced Net Debt/Adjusted EBITDA ratio (fourth quarter
annualized)1 to 1.9x at fourth-quarter 2021 from 2.4x at
fourth-quarter 2020
- Issued two comprehensive ESG and Climate Risk Reports with data
through year-end 2020, establishing goals for reducing greenhouse
gas and methane emissions, as well as the elimination of routine
flaring by 2025
Fourth-Quarter 2021
Highlights
- Closed acquisition of ~20,000 net acres in western Glasscock
County for ~$203 million, net of customary closing price
adjustments
- Generated Adjusted EBITDA1 of $182.2 million and Free Cash
Flow1 of $24.8 million
- Produced 41,080 barrels of oil per day ("BOPD") and 85,240
barrels of oil equivalent per day ("BOEPD"), an increase of 87% and
3%, respectively, versus fourth-quarter 2020, exceeding guidance
ranges for both metrics
- Increased oil cut as a percentage of total production to 48% in
fourth-quarter 2021 versus 27% in fourth-quarter 2020
- Incurred capital expenditures of $142 million, excluding
non-budgeted acquisitions and leasehold expenditures, completing 18
wells with 26 turn-in lines ("TIL") during the quarter
"We posted exceptional results in 2021 and enter
2022 with strong momentum and a clearly defined strategy to add
value for shareholders," stated Jason Pigott, President and Chief
Executive Officer. "Our team identified and closed two acquisitions
that significantly expanded our oil-weighted leasehold in Howard
and western Glasscock counties and extended our runway of
high-margin drilling locations. We strengthened our balance sheet,
purposefully funding portions of the acquisitions with equity and
proceeds from the divestiture of lower-margin gas-weighted
reserves. Our capital today is being allocated to our highest
return opportunities in Howard and western Glasscock counties. We
also furthered our commitment to sustainable development, setting
meaningful emissions reduction goals and allocating necessary
capital to ensure their attainment."
"Our outlook for 2022 is strong and our
disciplined development plan will build upon our successes from
2021," continued Mr. Pigott. "We are focused on capital efficient
development, generation of Free Cash Flow1 and leverage reduction.
We expect to achieve our initial leverage target of 1.5x Net
Debt/Adjusted EBITDA1 in the third quarter of 2022 and to be below
1.0x by the second half of 2023. As we further strengthen our
capital structure, we expect to be in a position to return cash to
shareholders in early 2023."
Fourth-Quarter and Full-Year 2021
Financial Results
For the fourth quarter of 2021, the Company
reported net income attributable to common stockholders of $216.3
million, or $12.84 per diluted share. Adjusted Net Income1 for the
fourth quarter of 2021 was $57.2 million, or $3.39 per adjusted
diluted share. Adjusted EBITDA1 for the fourth quarter of 2021 was
$182.2 million.
For full-year 2021, the Company reported net
income attributable to common stockholders of $145.0 million, or
$10.03 per diluted share. Adjusted Net Income1 for full-year 2021
was $128.9 million, or $8.91 per adjusted diluted share. Adjusted
EBITDA1 for full-year 2021 was $505.9 million.
1Non-GAAP financial measure; please see
supplemental reconciliations of GAAP to non-GAAP financial measures
at the end of this release.
Oil-Weighted Inventory Update
A key pillar of Laredo's strategy since 2019 has
been the acquisition and development of oil-weighted, high-margin
inventory. During 2021, the Company sourced and closed two
transformational transactions, one in Howard County and one in
western Glasscock County, significantly expanding Laredo's
oil-weighted inventory.
In Howard County, pro-forma for the acquisition
closed in July 2021, the Company had an estimated 225 Lower
Spraberry and Wolfcamp A locations, 61 of which were developed in
2021. In late 2021, the Company drilled two appraisal wells in the
Middle Spraberry with initial oil productivity far exceeding
initial expectations. Based on these results, Laredo has
incorporated ~35 Middle Spraberry wells, with an estimated
breakeven WTI oil price of <$55 per barrel, into the Company's
development inventory.
Laredo is focused on further enhancing capital
efficiency in Howard County with extended-reach laterals. The
Company has successfully combined 52 10,000-foot and shorter
laterals into 26 highly capital efficient 15,000-foot locations.
Laredo estimates current development inventory in Howard County to
be ~165 locations with an average lateral length of ~11,500
feet.
In western Glasscock County, pro-forma for the
acquisition closed in October 2021, the Company had an estimated
175 Lower Spraberry, Wolfcamp A and Wolfcamp B locations, eight of
which were developed in 2021. As part of the western Glasscock
County development package completed in the fourth quarter of 2021,
Laredo developed two Wolfcamp D appraisal wells. The Company has
significant experience developing the Wolfcamp D and, based on
prior production data, optimized the completion of these two
appraisal wells. Initial oil productivity is outperforming
expectations, driving an estimated breakeven WTI oil price for
Wolfcamp D wells in western Glasscock of $45 - $50 per barrel. The
Company has incorporated ~90 Wolfcamp D wells into its western
Glasscock inventory.
At the time of the announcement of the western
Glasscock acquisition that closed in October 2021, Laredo estimated
~135 oil-weighted locations associated with the acquisition. After
further evaluation, the Company now estimates ~150 locations on the
acquired properties. Combining existing western Glasscock holdings
with the acquired properties, Laredo now estimates an inventory of
~205 Lower Spraberry, Wolfcamp A and Wolfcamp B locations in
western Glasscock County. Combined with the Wolfcamp D inventory,
Laredo estimates a total of ~295 oil-weighted locations in western
Glasscock County.
Laredo estimates combined Howard and western
Glasscock County oil-weighted inventory of ~460 locations, with
breakeven WTI oil prices ranging from <$40 to <$55 per
barrel. At a current development cadence of 55 - 60 wells per year,
the Company has an approximately eight-year runway of oil-weighted
inventory. Laredo remains committed to a returns-focused
development strategy and expects to focus primarily on
higher-margin Howard County development in 2022 and 2023.
In the Company's eastern (legacy) acreage,
Laredo estimates another ~150 locations with a potential WTI
breakeven of <$55 per barrel. Adding these locations into
inventory will require additional technical evaluation and, in many
cases, the formation of drilling units to optimize returns by
extending laterals.
Operations Summary
In the fourth quarter of 2021, the Company's
total and oil production averaged 85,240 BOEPD and 41,080 BOPD,
respectively. Both metrics exceeded the high-end of guidance,
driven by strong well performance in Howard and western Glasscock
counties, including the test of the Middle Spraberry in Howard
County. Total and oil production for full-year 2021 averaged 81,717
BOEPD and 31,833 BOPD, respectively, with both metrics above the
high-end of guidance.
Lease operating expenses ("LOE") for
fourth-quarter 2021 were $4.27 per BOE, relatively flat from $4.23
in third-quarter 2021 and in-line with expectations. For full-year
2021, LOE increased to $3.42 versus $2.55 for full-year 2020 as the
Company transitioned operations to higher-margin properties in
Howard County. Operating expenses in Howard County are higher than
the Company's gas-weighted eastern acreage because the oilier
properties require different methods of artificial lift that are
higher-cost, however, such costs are more than overcome by the
higher-margins in Howard County.
During fourth-quarter 2021, Laredo maintained
its best-in-class venting/flaring performance and made significant
strides reducing venting/flaring on its acquired properties in
Howard County. Excluding recently acquired assets in Howard County,
Laredo vented/flared 0.38% of produced gas during the
fourth-quarter 2021, down from 0.55% during the prior quarter. The
Company reduced vented/flared volumes on the acquired properties in
Howard County by 81% versus third-quarter 2021, and reduced total
Company vented/flared volumes to 0.61% of produced gas during
fourth-quarter 2021, down from 1.89% in the prior quarter. For
full-year 2021, excluding acquired assets, Laredo vented/flared
0.37% of produced gas, down from 0.71% in full-year 2020.
In the fourth quarter of 2021, the Company
completed 18 wells, including 26 TILs, with capital expenditures of
$142 million, excluding non-budgeted and leasehold acquisitions.
Capital expenditures were higher than expectations, primarily
related to inflationary pressures on steel and additional
non-operated investments in the recent acquisition areas. For
full-year 2021, Laredo completed 67 wells, including 71 TILs, with
total capital expenditures of $444 million, excluding non-budgeted
acquisitions and leasehold expenditures.
Laredo is currently operating three drilling
rigs and two completions crews and expects to complete and TIL 18
wells during the first quarter of 2022. Laredo expects to release
one drilling rig and one completions crew by the end of the
first-quarter of 2022 and to maintain a two rig/one crew cadence
for the remainder of 2022.
2021 Proved Reserves
The Company's total proved reserves increased
15% in 2021, with proved oil reserves increasing 78%, benefiting
from Laredo's strategy of acquiring and developing high-return
oil-weighted assets. The Company's reserves were valued at $3.4
billion at year-end 2021, based on SEC benchmark pricing of $63.04
per barrel for oil and $3.35 per MMBtu for natural gas. The PV-10
value was $3.7 billion, utilizing the same benchmark prices.
The divestiture of gas-weighted reserves during
2021, combined with the oil-weighted acquisitions, contributed to
the increase of oil reserves as a percentage of total reserves to
38% versus 24% the previous year, driving a significant increase in
reserve value at higher oil prices. At benchmark prices of $75 WTI
and $3.50 NYMEX Henry Hub, the Company estimates the PV-10 value of
its year-end 2021 reserves to be $4.6 billion.
Environmental, Social,
Governance
Throughout 2021, Laredo made significant strides
furthering its already robust environmental, social and governance
("ESG") commitments. The Company's board of directors amended the
Nominating and Corporate Governance Committee's charter to include
monitoring and evaluation of programs and policies related to ESG
matters. The Company established goals for meaningful reductions of
greenhouse gas and methane emissions and the elimination of routine
flaring by 2025. Additionally, Laredo announced the appointment of
a Chief Sustainability Officer and issued two comprehensive ESG and
Climate Risk Reports, utilizing reporting standards and frameworks
aligned with the Sustainability Accounting Standards Board and the
Task Force on Climate-related Financial Disclosures. These reports
are available on the Company's website at www.laredopetro.com,
under the tab for "Sustainability."
In 2022, for the third consecutive year, Laredo
has incorporated environmental metrics into the Company's executive
compensation program. For the 2022 short-term incentive program,
the metrics have been broadened to include a safety goal, in
addition to the spills and flaring goals from the previous two
years. Further emphasizing the Company's commitment to sustainable
development, three-year emissions reductions targets were
incorporated into the long-term incentive plan portion of executive
compensation.
Additionally, Laredo increased the transparency
of its diversity practices, including disclosure of EEO-1 data in
Laredo's 2021 ESG and Climate Risk Report and, in responding to
shareholder input, implemented a majority voting standard for
director elections and an executive clawback plan.
Incurred Capital Expenditures
During the fourth quarter of 2021, total
incurred capital expenditures were $142 million, excluding
non-budgeted acquisitions and leasehold expenditures. Investments
were higher than expectations due to industry-wide oil field
service inflation and non-operated investments. Total investments
were comprised of $117 million in drilling and completions
activities, including $8 million of non-operated capital, $7
million in land, exploration and data related costs, $10 million in
infrastructure, including Laredo Midstream Services investments,
and $8 million in other capitalized costs.
For full-year 2021, total incurred capital
expenditures were $444 million, excluding non-budgeted acquisitions
and leasehold expenditures. Total investments were comprised of
$368 million in drilling and completions activities, including $9
million of non-operated capital, $23 million in land, exploration
and data related costs, $28 million in infrastructure, including
Laredo Midstream Services investments, and $25 million in other
capitalized costs.
Liquidity
At December 31, 2021, the Company had outstanding
borrowings of $105 million on its $725 million senior secured
credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $576 million.
Including cash and cash equivalents of $57 million, total liquidity
was $633 million.
At February 21, 2022, the Company had
outstanding borrowings of $145 million on its $725 million senior
secured credit facility, resulting in available capacity, after the
reduction for outstanding letters of credit, of $536 million.
Including cash and cash equivalents of $12 million, total liquidity
was $548 million.
First-Quarter and Full-Year 2022
Guidance
The table below reflects the Company's guidance
for total and oil production for first-quarter and full-year
2022.
|
1Q-22E |
|
FY-22E |
Total
production (MBOE per day) |
84.0 - 87.0 |
|
82.0 - 86.0 |
Oil
production (MBOPD) |
39.5 -
41.5 |
|
39.5 -
42.5 |
Incurred
capital expenditures, excluding non-budgeted acquisitions ($
MM) |
~170 |
|
~520 |
The table below reflects the Company's guidance
for select revenue and expense items for the first quarter of
2022.
|
1Q-22E |
Average
sales price realizations (excluding derivatives): |
|
Oil (% of WTI) |
100% |
NGL (% of WTI) |
34% |
Natural gas (% of Henry
Hub) |
68% |
|
|
Net
settlements received (paid) for matured commodity derivatives ($
MM): |
|
Oil |
($82) |
NGL |
($11) |
Natural gas |
($9) |
|
|
Other ($
MM): |
|
Net income
(expense) of purchased
oil |
($3.0) |
|
|
Selected
average costs & expenses: |
|
Lease operating expenses
($/BOE) |
$4.25 |
Production and ad valorem taxes (% of oil, NGL and natural gas
sales
revenues) |
7.00% |
Transportation and marketing expenses
($/BOE) |
$1.90 |
General and administrative expenses (excluding LTIP,
$/BOE) |
$1.65 |
General and administrative expenses (LTIP cash,
$/BOE) |
$0.30 |
General and administrative expenses (LTIP non-cash,
$/BOE) |
$0.25 |
Depletion, depreciation and amortization
($/BOE) |
$9.75 |
Conference Call Details
On Wednesday, February 23, 2022, at 7:30 a.m.
CT, Laredo will host a conference call to discuss its
fourth-quarter and full-year 2021 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
3342479, 10 minutes prior to the scheduled conference time. A
telephonic replay will be available two hours after the call
through Wednesday, March 2, 2022. Participants may access this
replay by dialing 855.859.2056, using conference code 3342479.
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. Such
statements are not guarantees of future performance and involve
risks, assumptions and uncertainties. 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, the ability of the Company to execute its
strategies, including its ability to successfully identify and
consummate strategic acquisitions at purchase prices that are
accretive to its financial results and to successfully integrate
acquired businesses, assets and properties, 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, 2020, Current Report on
Form 8-K, filed with the Securities and Exchange Commission ("SEC")
on May 11, 2021, and those set forth from time to time in other
filings with the 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, |
|
Year ended December 31, |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
(unaudited) |
|
(unaudited) |
Sales
volumes: |
|
|
|
|
|
|
|
Oil (MBbl) |
|
3,779 |
|
|
|
2,018 |
|
|
11,619 |
|
|
9,827 |
NGL (MBbl) |
|
1,976 |
|
|
|
2,636 |
|
|
8,678 |
|
|
10,615 |
Natural gas
(MMcf) |
|
12,516 |
|
|
|
17,648 |
|
|
57,175 |
|
|
70,049 |
Oil equivalents
(MBOE)(1)(2) |
|
7,842 |
|
|
|
7,595 |
|
|
29,827 |
|
|
32,117 |
Average daily oil equivalent sales volumes
(BOE/D)(2) |
|
85,240 |
|
|
|
82,552 |
|
|
81,717 |
|
|
87,750 |
Average daily oil sales volumes
(Bbl/D)(2) |
|
41,080 |
|
|
|
21,929 |
|
|
31,833 |
|
|
26,849 |
Average
sales prices(2): |
|
|
|
|
|
|
|
Oil ($/Bbl)(3) |
$ |
76.92 |
|
|
$ |
41.82 |
|
$ |
69.32 |
|
$ |
37.43 |
NGL ($/Bbl)(3)(5) |
$ |
29.58 |
|
|
$ |
10.82 |
|
$ |
22.08 |
|
$ |
7.37 |
Natural
gas ($/Mcf)(3)(5) |
$ |
4.15 |
|
|
$ |
1.19 |
|
$ |
2.63 |
|
$ |
0.72 |
Average sales price
($/BOE)(3) |
$ |
51.15 |
|
|
$ |
17.63 |
|
$ |
38.46 |
|
$ |
15.45 |
Oil, with commodity
derivatives ($/Bbl)(4) |
$ |
57.83 |
|
|
$ |
60.52 |
|
$ |
52.09 |
|
$ |
56.41 |
NGL, with commodity
derivatives ($/Bbl)(4) |
$ |
11.07 |
|
|
$ |
11.43 |
|
$ |
10.55 |
|
$ |
9.12 |
Natural gas, with commodity
derivatives ($/Mcf)(4) |
$ |
1.69 |
|
|
$ |
1.31 |
|
$ |
1.56 |
|
$ |
1.02 |
Average sales price, with commodity derivatives
($/BOE)(4) |
$ |
33.36 |
|
|
$ |
23.08 |
|
$ |
26.36 |
|
$ |
22.50 |
Selected
average costs and expenses per BOE sold(2): |
|
|
|
|
|
|
|
Lease operating
expenses |
$ |
4.27 |
|
|
$ |
2.57 |
|
$ |
3.42 |
|
$ |
2.55 |
Production and ad valorem
taxes |
|
2.91 |
|
|
|
1.07 |
|
|
2.30 |
|
|
1.03 |
Transportation and marketing
expenses |
|
1.71 |
|
|
|
1.59 |
|
|
1.61 |
|
|
1.55 |
Midstream service
expenses |
|
0.14 |
|
|
|
0.09 |
|
|
0.12 |
|
|
0.12 |
General and administrative (excluding
LTIP) |
|
1.58 |
|
|
|
1.71 |
|
|
1.54 |
|
|
1.29 |
Total selected operating
expenses |
$ |
10.61 |
|
|
$ |
7.03 |
|
$ |
8.99 |
|
$ |
6.54 |
General and administrative (LTIP): |
|
|
|
|
|
|
|
LTIP cash |
$ |
(0.08 |
) |
|
$ |
0.12 |
|
$ |
0.35 |
|
$ |
0.06 |
LTIP non-cash |
$ |
0.23 |
|
|
$ |
0.25 |
|
$ |
0.22 |
|
$ |
0.22 |
Depletion, depreciation and amortization |
$ |
9.51 |
|
|
$ |
5.56 |
|
$ |
7.22 |
|
$ |
6.76 |
_______________________________________________________________________________
(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. |
(5) |
|
Prices presented for the three months ended December 31, 2021 have
been updated from preliminary estimates previously provided in the
Company's Current Report on Form 8-K dated January 19, 2022. These
changes are the result of final accounting presentation
requirements which require the Company's contractual minimum
volumes to its customers be recorded as a reduction to the
transaction price, as these amounts do not represent payments to
the customer for distinct goods or services and instead relate
specifically to the failure to perform under the specific customer
contract. Such amounts are recorded as a reduction to the
transaction price when payment is determined as probable, typically
when such a deficiency occurs. |
Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data) |
|
December 31, 2021 |
|
December 31, 2020 |
|
|
(unaudited) |
Assets |
|
|
|
|
Current
assets: |
|
|
|
|
Cash and cash
equivalents |
|
$ |
56,798 |
|
|
$ |
48,757 |
|
Accounts receivable,
net |
|
|
151,807 |
|
|
|
63,976 |
|
Derivatives |
|
|
4,346 |
|
|
|
7,893 |
|
Other current
assets |
|
|
22,906 |
|
|
|
15,964 |
|
Total current
assets |
|
|
235,857 |
|
|
|
136,590 |
|
Property and
equipment: |
|
|
|
|
Oil and natural gas properties, full cost method: |
|
|
|
|
Evaluated
properties |
|
|
8,968,668 |
|
|
|
7,874,932 |
|
Unevaluated properties not being
depleted |
|
|
170,033 |
|
|
|
70,020 |
|
Less: accumulated depletion and
impairment |
|
|
(7,019,670 |
) |
|
|
(6,817,949 |
) |
Oil and natural gas properties,
net |
|
|
2,119,031 |
|
|
|
1,127,003 |
|
Midstream service assets,
net |
|
|
96,528 |
|
|
|
112,697 |
|
Other fixed assets,
net |
|
|
34,590 |
|
|
|
32,011 |
|
Property and equipment,
net |
|
|
2,250,149 |
|
|
|
1,271,711 |
|
Derivatives |
|
|
32,963 |
|
|
|
— |
|
Operating
lease right-of-use
assets |
|
|
11,514 |
|
|
|
17,973 |
|
Other
noncurrent assets,
net |
|
|
21,341 |
|
|
|
16,336 |
|
Total assets |
|
$ |
2,551,824 |
|
|
$ |
1,442,610 |
|
Liabilities and stockholders' equity |
|
|
|
|
Current
liabilities: |
|
|
|
|
Accounts payable and accrued
liabilities |
|
$ |
71,386 |
|
|
$ |
38,279 |
|
Accrued capital
expenditures |
|
|
50,585 |
|
|
|
28,275 |
|
Undistributed revenue and
royalties |
|
|
117,920 |
|
|
|
24,728 |
|
Derivatives |
|
|
179,809 |
|
|
|
31,826 |
|
Operating lease
liabilities |
|
|
7,742 |
|
|
|
11,721 |
|
Other current
liabilities |
|
|
99,471 |
|
|
|
62,766 |
|
Total current
liabilities |
|
|
526,913 |
|
|
|
197,595 |
|
Long-term
debt, net |
|
|
1,425,858 |
|
|
|
1,179,266 |
|
Derivatives |
|
|
— |
|
|
|
12,051 |
|
Asset
retirement
obligations |
|
|
69,057 |
|
|
|
64,775 |
|
Operating
lease
liabilities |
|
|
5,726 |
|
|
|
8,918 |
|
Other
noncurrent
liabilities |
|
|
10,490 |
|
|
|
1,448 |
|
Total
liabilities |
|
|
2,038,044 |
|
|
|
1,464,053 |
|
Commitments
and contingencies |
|
|
|
|
Stockholders' equity: |
|
|
|
|
Preferred stock, $0.01 par value, 50,000,000 shares authorized and
zero issued as of December 31, 2021 and December 31,
2020 |
|
|
— |
|
|
|
— |
|
Common stock, $0.01 par value, 22,500,000 shares authorized and
17,074,516 and 12,020,164 issued and outstanding as of December 31,
2021 and December 31, 2020,
respectively |
|
|
171 |
|
|
|
120 |
|
Additional paid-in
capital |
|
|
2,788,628 |
|
|
|
2,398,464 |
|
Accumulated
deficit |
|
|
(2,275,019 |
) |
|
|
(2,420,027 |
) |
Total stockholders'
equity |
|
|
513,780 |
|
|
|
(21,443 |
) |
Total liabilities and stockholders'
equity |
|
$ |
2,551,824 |
|
|
$ |
1,442,610 |
|
|
Laredo Petroleum, Inc.
Consolidated statements of operations
|
|
Three months ended December 31, |
|
Year ended December 31, |
(in thousands, except per share data) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
290,696 |
|
|
$ |
84,380 |
|
|
$ |
805,448 |
|
|
$ |
367,792 |
|
NGL sales |
|
|
58,470 |
|
|
|
28,525 |
|
|
|
191,591 |
|
|
|
78,246 |
|
Natural gas
sales |
|
|
51,918 |
|
|
|
20,960 |
|
|
|
150,104 |
|
|
|
50,317 |
|
Midstream service
revenues |
|
|
2,337 |
|
|
|
1,534 |
|
|
|
6,629 |
|
|
|
8,249 |
|
Sales of purchased
oil |
|
|
66,803 |
|
|
|
52,666 |
|
|
|
240,303 |
|
|
|
172,588 |
|
Total revenues |
|
|
470,224 |
|
|
|
188,065 |
|
|
|
1,394,075 |
|
|
|
677,192 |
|
Costs and
expenses: |
|
|
|
|
|
|
|
|
Lease operating
expenses |
|
|
33,468 |
|
|
|
19,549 |
|
|
|
101,994 |
|
|
|
82,020 |
|
Production and ad valorem
taxes |
|
|
22,785 |
|
|
|
8,115 |
|
|
|
68,742 |
|
|
|
33,050 |
|
Transportation and marketing
expenses |
|
|
13,439 |
|
|
|
12,041 |
|
|
|
47,916 |
|
|
|
49,927 |
|
Midstream service
expenses |
|
|
1,135 |
|
|
|
704 |
|
|
|
3,707 |
|
|
|
3,762 |
|
Costs of purchased
oil |
|
|
67,603 |
|
|
|
56,728 |
|
|
|
251,061 |
|
|
|
194,862 |
|
General and
administrative |
|
|
13,619 |
|
|
|
15,840 |
|
|
|
62,801 |
|
|
|
50,534 |
|
Organizational restructuring
expenses |
|
|
— |
|
|
|
— |
|
|
|
9,800 |
|
|
|
4,200 |
|
Depletion, depreciation and
amortization |
|
|
74,592 |
|
|
|
42,210 |
|
|
|
215,355 |
|
|
|
217,101 |
|
Impairment
expense |
|
|
— |
|
|
|
109,804 |
|
|
|
1,613 |
|
|
|
899,039 |
|
Other operating
expenses |
|
|
134 |
|
|
|
1,105 |
|
|
|
4,233 |
|
|
|
4,430 |
|
Total costs and
expenses |
|
|
226,775 |
|
|
|
266,096 |
|
|
|
767,222 |
|
|
|
1,538,925 |
|
Gain on sale of oil and natural gas properties,
net |
|
|
— |
|
|
|
— |
|
|
|
93,482 |
|
|
|
— |
|
Operating
income (loss) |
|
|
243,449 |
|
|
|
(78,031 |
) |
|
|
720,335 |
|
|
|
(861,733 |
) |
Non-operating income (expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives,
net |
|
|
15,372 |
|
|
|
(81,935 |
) |
|
|
(452,175 |
) |
|
|
80,114 |
|
Interest
expense |
|
|
(31,163 |
) |
|
|
(26,139 |
) |
|
|
(113,385 |
) |
|
|
(105,009 |
) |
Gain on extinguishment of debt,
net |
|
|
— |
|
|
|
22,309 |
|
|
|
— |
|
|
|
8,989 |
|
Gain (loss) on disposal of assets,
net |
|
|
(8,903 |
) |
|
|
94 |
|
|
|
(8,931 |
) |
|
|
(963 |
) |
Write-off of debt issuance
costs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(1,103 |
) |
Other income,
net |
|
|
573 |
|
|
|
978 |
|
|
|
2,809 |
|
|
|
1,586 |
|
Total non-operating income (expense),
net |
|
|
(24,121 |
) |
|
|
(84,693 |
) |
|
|
(571,682 |
) |
|
|
(16,386 |
) |
Income (loss) before income
taxes |
|
|
219,328 |
|
|
|
(162,724 |
) |
|
|
148,653 |
|
|
|
(878,119 |
) |
Income tax
(expense) benefit: |
|
|
|
|
|
|
|
|
Current |
|
|
(24 |
) |
|
|
— |
|
|
|
(1,324 |
) |
|
|
— |
|
Deferred |
|
|
(3,028 |
) |
|
|
(3,208 |
) |
|
|
(2,321 |
) |
|
|
3,946 |
|
Total income tax (expense)
benefit |
|
|
(3,052 |
) |
|
|
(3,208 |
) |
|
|
(3,645 |
) |
|
|
3,946 |
|
Net income
(loss) |
|
$ |
216,276 |
|
|
$ |
(165,932 |
) |
|
$ |
145,008 |
|
|
$ |
(874,173 |
) |
Net income
(loss) per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
13.07 |
|
|
$ |
(14.18 |
) |
|
$ |
10.18 |
|
|
$ |
(74.92 |
) |
Diluted |
|
$ |
12.84 |
|
|
$ |
(14.18 |
) |
|
$ |
10.03 |
|
|
$ |
(74.92 |
) |
Weighted-average common shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
|
16,545 |
|
|
|
11,702 |
|
|
|
14,240 |
|
|
|
11,668 |
|
Diluted |
|
|
16,846 |
|
|
|
11,702 |
|
|
|
14,464 |
|
|
|
11,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum, Inc.
Condensed consolidated statements of cash
flows
|
|
Three months ended December 31, |
|
Year ended December 31, |
(in thousands) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows
from operating activities: |
|
|
|
|
|
|
|
|
Net income
(loss) |
|
$ |
216,276 |
|
|
$ |
(165,932 |
) |
|
$ |
145,008 |
|
|
$ |
(874,173 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating
activities: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation,
net |
|
|
2,066 |
|
|
|
2,106 |
|
|
|
7,675 |
|
|
|
8,217 |
|
Depletion, depreciation and
amortization |
|
|
74,592 |
|
|
|
42,210 |
|
|
|
215,355 |
|
|
|
217,101 |
|
Impairment
expense |
|
|
— |
|
|
|
109,804 |
|
|
|
1,613 |
|
|
|
899,039 |
|
Gain on sale of oil and natural gas properties,
net |
|
|
— |
|
|
|
— |
|
|
|
(93,482 |
) |
|
|
— |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives,
net |
|
|
(15,372 |
) |
|
|
81,935 |
|
|
|
452,175 |
|
|
|
(80,114 |
) |
Settlements (paid) received for matured derivatives,
net |
|
|
(129,361 |
) |
|
|
41,786 |
|
|
|
(320,868 |
) |
|
|
228,221 |
|
Settlements received for early-terminated commodity derivatives,
net |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,340 |
|
Premiums received (paid) for commodity
derivatives |
|
|
— |
|
|
|
— |
|
|
|
9,041 |
|
|
|
(51,070 |
) |
Gain on extinguishment of debt,
net |
|
|
— |
|
|
|
(22,309 |
) |
|
|
— |
|
|
|
(8,989 |
) |
Deferred income tax expense
(benefit) |
|
|
3,028 |
|
|
|
3,208 |
|
|
|
2,321 |
|
|
|
(3,946 |
) |
Other, net |
|
|
15,417 |
|
|
|
4,767 |
|
|
|
32,319 |
|
|
|
22,723 |
|
Cash flows from operating activities before changes in operating
assets and liabilities,
net |
|
|
166,646 |
|
|
|
97,575 |
|
|
|
451,157 |
|
|
|
363,349 |
|
Change in current assets and liabilities,
net |
|
|
22,215 |
|
|
|
17,601 |
|
|
|
49,321 |
|
|
|
36,699 |
|
Change in noncurrent assets and liabilities,
net |
|
|
20,698 |
|
|
|
(5,406 |
) |
|
|
(3,807 |
) |
|
|
(16,658 |
) |
Net cash provided by operating
activities |
|
|
209,559 |
|
|
|
109,770 |
|
|
|
496,671 |
|
|
|
383,390 |
|
Cash flows
from investing activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties,
net |
|
|
(136,367 |
) |
|
|
(12,223 |
) |
|
|
(763,411 |
) |
|
|
(35,786 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas
properties |
|
|
(139,515 |
) |
|
|
(69,082 |
) |
|
|
(418,362 |
) |
|
|
(347,359 |
) |
Midstream service
assets |
|
|
(474 |
) |
|
|
(654 |
) |
|
|
(2,849 |
) |
|
|
(3,171 |
) |
Other fixed
assets |
|
|
(2,705 |
) |
|
|
(1,235 |
) |
|
|
(5,931 |
) |
|
|
(4,259 |
) |
Proceeds from dispositions of capital assets, net of selling
costs |
|
|
— |
|
|
|
95 |
|
|
|
393,742 |
|
|
|
1,337 |
|
Net cash used in investing
activities |
|
|
(279,061 |
) |
|
|
(83,099 |
) |
|
|
(796,811 |
) |
|
|
(389,238 |
) |
Cash flows
from financing activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit
Facility |
|
|
145,000 |
|
|
|
35,000 |
|
|
|
570,000 |
|
|
|
80,000 |
|
Payments on Senior Secured Credit
Facility |
|
|
(70,000 |
) |
|
|
(15,000 |
) |
|
|
(720,000 |
) |
|
|
(200,000 |
) |
Issuance of January 2025 Notes and January 2028
Notes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,000,000 |
|
Issuance of July 2029
Notes |
|
|
— |
|
|
|
— |
|
|
|
400,000 |
|
|
|
— |
|
Extinguishment of
debt |
|
|
— |
|
|
|
(38,139 |
) |
|
|
— |
|
|
|
(846,994 |
) |
Proceeds from issuance of common stock, net of offering
costs |
|
|
— |
|
|
|
— |
|
|
|
72,492 |
|
|
|
— |
|
Payments for debt issuance
costs |
|
|
(89 |
) |
|
|
(28 |
) |
|
|
(14,686 |
) |
|
|
(18,479 |
) |
Other, net |
|
|
(7 |
) |
|
|
(5 |
) |
|
|
375 |
|
|
|
(779 |
) |
Net cash provided by (used in) financing
activities |
|
|
74,904 |
|
|
|
(18,172 |
) |
|
|
308,181 |
|
|
|
13,748 |
|
Net increase
in cash and cash equivalents |
|
|
5,402 |
|
|
|
8,499 |
|
|
|
8,041 |
|
|
|
7,900 |
|
Cash and
cash equivalents, beginning of
period |
|
|
51,396 |
|
|
|
40,258 |
|
|
|
48,757 |
|
|
|
40,857 |
|
Cash and
cash equivalents, end of
period |
|
$ |
56,798 |
|
|
$ |
48,757 |
|
|
$ |
56,798 |
|
|
$ |
48,757 |
|
|
Laredo Petroleum, Inc.
Total incurred capital expenditures
The following table presents the components of
the Company's incurred capital expenditures, excluding non-budgeted
acquisition costs, for the periods presented:
|
|
Three months ended December 31, |
|
Year ended December 31, |
(in thousands) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas
properties |
|
$ |
137,892 |
|
$ |
74,223 |
|
$ |
444,337 |
|
$ |
344,160 |
Midstream
service assets |
|
|
420 |
|
|
288 |
|
|
2,842 |
|
|
2,985 |
Other fixed
assets |
|
|
3,578 |
|
|
1,056 |
|
|
6,807 |
|
|
4,148 |
Total incurred capital expenditures, excluding non-budgeted
acquisition
costs |
|
$ |
141,890 |
|
$ |
75,567 |
|
$ |
453,986 |
|
$ |
351,293 |
|
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, Adjusted EBITDA, PV-10 and Net Debt, 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, Adjusted EBITDA, PV-10 and Net Debt 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 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 incurred capital expenditures, 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 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, |
|
Year ended December 31, |
(in thousands) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating
activities |
|
$ |
209,559 |
|
$ |
109,770 |
|
|
$ |
496,671 |
|
|
$ |
383,390 |
|
Less: |
|
|
|
|
|
|
|
|
Change in current assets and liabilities,
net |
|
|
22,215 |
|
|
17,601 |
|
|
|
49,321 |
|
|
|
36,699 |
|
Change in noncurrent assets and liabilities,
net |
|
|
20,698 |
|
|
(5,406 |
) |
|
|
(3,807 |
) |
|
|
(16,658 |
) |
Cash flows
from operating activities before changes in operating assets and
liabilities,
net |
|
|
166,646 |
|
|
97,575 |
|
|
|
451,157 |
|
|
|
363,349 |
|
Less incurred capital expenditures, excluding non-budgeted
acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas
properties(1) |
|
|
137,892 |
|
|
74,223 |
|
|
|
444,337 |
|
|
|
344,160 |
|
Midstream service
assets(1) |
|
|
420 |
|
|
288 |
|
|
|
2,842 |
|
|
|
2,985 |
|
Other fixed
assets |
|
|
3,578 |
|
|
1,056 |
|
|
|
6,807 |
|
|
|
4,148 |
|
Total incurred capital expenditures, excluding non-budgeted
acquisition costs
|
|
|
141,890 |
|
|
75,567 |
|
|
|
453,986 |
|
|
|
351,293 |
|
Free Cash
Flow (non-GAAP)
|
|
$ |
24,756 |
|
$ |
22,008 |
|
|
$ |
(2,829 |
) |
|
$ |
12,056 |
|
_____________________________________________________________________________
(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 (GAAP) plus adjustments for mark-to-market on derivatives,
premiums paid or received 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
income (loss) before income taxes (GAAP) to Adjusted Net Income
(non-GAAP) for the periods presented:
|
|
Three months ended December 31, |
|
Year ended December 31, |
(in thousands, except per share data) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Income (loss) before income
taxes |
|
$ |
219,328 |
|
|
$ |
(162,724 |
) |
|
$ |
148,653 |
|
|
$ |
(878,119 |
) |
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives,
net |
|
|
(15,372 |
) |
|
|
81,935 |
|
|
|
452,175 |
|
|
|
(80,114 |
) |
Settlements (paid) received for matured derivatives,
net |
|
|
(129,361 |
) |
|
|
41,786 |
|
|
|
(320,868 |
) |
|
|
228,221 |
|
Settlements received for early-terminated commodity derivatives,
net |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,340 |
|
Net premiums paid for commodity derivatives that matured during the
period(1) |
|
|
(10,183 |
) |
|
|
— |
|
|
|
(41,553 |
) |
|
|
(477 |
) |
Organizational restructuring
expenses |
|
|
— |
|
|
|
— |
|
|
|
9,800 |
|
|
|
4,200 |
|
Impairment
expense |
|
|
— |
|
|
|
109,804 |
|
|
|
1,613 |
|
|
|
899,039 |
|
Gain on sale of oil and natural gas properties,
net |
|
|
— |
|
|
|
— |
|
|
|
(93,482 |
) |
|
|
— |
|
Gain on extinguishment of debt,
net |
|
|
— |
|
|
|
(22,309 |
) |
|
|
— |
|
|
|
(8,989 |
) |
(Gain) loss on disposal of assets,
net |
|
|
8,903 |
|
|
|
(94 |
) |
|
|
8,931 |
|
|
|
963 |
|
Write-off of debt issuance
costs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,103 |
|
Adjusted income before adjusted income tax
expense |
|
|
73,315 |
|
|
|
48,398 |
|
|
|
165,269 |
|
|
|
172,167 |
|
Adjusted income tax
expense(2) |
|
|
(16,129 |
) |
|
|
(10,648 |
) |
|
|
(36,359 |
) |
|
|
(37,877 |
) |
Adjusted Net Income
(non-GAAP) |
|
$ |
57,186 |
|
|
$ |
37,750 |
|
|
$ |
128,910 |
|
|
$ |
134,290 |
|
Net income
(loss) per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
13.07 |
|
|
$ |
(14.18 |
) |
|
$ |
10.18 |
|
|
$ |
(74.92 |
) |
Diluted |
|
$ |
12.84 |
|
|
$ |
(14.18 |
) |
|
$ |
10.03 |
|
|
$ |
(74.92 |
) |
Adjusted Net
Income per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
3.46 |
|
|
$ |
3.23 |
|
|
$ |
9.05 |
|
|
$ |
11.51 |
|
Diluted |
|
$ |
3.39 |
|
|
$ |
3.23 |
|
|
$ |
8.91 |
|
|
$ |
11.51 |
|
Adjusted
diluted |
|
$ |
3.39 |
|
|
$ |
3.22 |
|
|
$ |
8.91 |
|
|
$ |
11.47 |
|
Weighted-average common shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
|
16,545 |
|
|
|
11,702 |
|
|
|
14,240 |
|
|
|
11,668 |
|
Diluted |
|
|
16,846 |
|
|
|
11,702 |
|
|
|
14,464 |
|
|
|
11,668 |
|
Adjusted
diluted |
|
|
16,846 |
|
|
|
11,709 |
|
|
|
14,464 |
|
|
|
11,712 |
|
_______________________________________________________________________________
(1) |
|
Reflects net premiums paid
previously or upon settlement that are attributable to derivatives
settled in the respective periods presented. |
(2) |
|
Adjusted income tax expense is
calculated by applying a statutory tax rate of 22% for each of the
periods ended December 31, 2021 and 2020. |
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure
that the Company defines as net income or loss (GAAP) plus
adjustments for share-settled equity-based compensation, depletion,
depreciation and amortization, impairment expense, mark-to-market
on derivatives, premiums paid or received 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 income (loss) (GAAP) to Adjusted EBITDA (non-GAAP) for the
periods presented:
|
|
Three months
ended December 31, |
|
Year ended
December 31, |
(in thousands) |
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
(unaudited) |
|
(unaudited) |
Net income
(loss) |
|
$ |
216,276 |
|
|
$ |
(165,932 |
) |
|
$ |
145,008 |
|
|
$ |
(874,173 |
) |
Plus: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation,
net |
|
|
2,066 |
|
|
|
2,106 |
|
|
|
7,675 |
|
|
|
8,217 |
|
Depletion, depreciation and
amortization |
|
|
74,592 |
|
|
|
42,210 |
|
|
|
215,355 |
|
|
|
217,101 |
|
Impairment
expense |
|
|
— |
|
|
|
109,804 |
|
|
|
1,613 |
|
|
|
899,039 |
|
Gain on sale of oil and natural gas properties,
net |
|
|
— |
|
|
|
— |
|
|
|
(93,482 |
) |
|
|
— |
|
Organizational restructuring
expenses |
|
|
— |
|
|
|
— |
|
|
|
9,800 |
|
|
|
4,200 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives,
net |
|
|
(15,372 |
) |
|
|
81,935 |
|
|
|
452,175 |
|
|
|
(80,114 |
) |
Settlements (paid) received for matured derivatives,
net |
|
|
(129,361 |
) |
|
|
41,786 |
|
|
|
(320,868 |
) |
|
|
228,221 |
|
Settlements received for early-terminated commodity derivatives,
net |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
6,340 |
|
Net premiums paid for commodity derivatives that matured during the
period(1) |
|
|
(10,183 |
) |
|
|
— |
|
|
|
(41,553 |
) |
|
|
(477 |
) |
Accretion
expense |
|
|
1,026 |
|
|
|
1,105 |
|
|
|
4,233 |
|
|
|
4,430 |
|
(Gain) loss on disposal of assets,
net |
|
|
8,903 |
|
|
|
(94 |
) |
|
|
8,931 |
|
|
|
963 |
|
Interest
expense |
|
|
31,163 |
|
|
|
26,139 |
|
|
|
113,385 |
|
|
|
105,009 |
|
Gain on extinguishment of debt,
net |
|
|
— |
|
|
|
(22,309 |
) |
|
|
— |
|
|
|
(8,989 |
) |
Write-off of debt issuance
costs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,103 |
|
Income tax expense
(benefit) |
|
|
3,052 |
|
|
|
3,208 |
|
|
|
3,645 |
|
|
|
(3,946 |
) |
Adjusted EBITDA
(non-GAAP) |
|
$ |
182,162 |
|
|
$ |
119,958 |
|
|
$ |
505,917 |
|
|
$ |
506,924 |
|
_____________________________________________________________________________
(1) |
|
Reflects net premiums paid
previously or upon settlement that are attributable to derivatives
settled in the respective periods presented. |
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, 2021 |
Standardized measure of discounted future net cash flows |
|
$ |
3,425 |
|
Less present
value of future income taxes discounted at 10% |
|
|
(291 |
) |
PV-10
(non-GAAP) |
|
$ |
3,716 |
|
Net Debt (Unaudited)
Net Debt, a non-GAAP financial measure, is
calculated as the face value of long-term debt less cash and cash
equivalents. 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. Net Debt as of
December 31, 2021 was $1.387 billion.
Net Debt to TTM Adjusted EBITDA
(Unaudited)
Net Debt to TTM Adjusted EBITDA is calculated as
Net Debt divided by trailing twelve-month Adjusted EBITDA. Net Debt
to Adjusted EBITDA is used by the Company’s management for various
purposes, including as a measure of operating performance, in
presentations to its board of directors and as a basis for
strategic planning and forecasting.
Investor Contact: Ron Hagood
918.858.5504 rhagood@laredopetro.com
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