Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its second-quarter 2020 results. For the second
quarter of 2020, the Company reported a net loss attributable to
common stockholders of $545.5 million, or $46.75 per diluted share.
Adjusted Net Income, a non-GAAP financial measure, for the second
quarter of 2020 was $28.4 million, or $2.43 per adjusted diluted
share. Adjusted EBITDA, a non-GAAP financial measure, for the
second quarter of 2020 was $132.8 million.
Please see supplemental financial information at the end of this
news release for reconciliations of non-GAAP financial measures,
including a calculation of Adjusted EBITDA, Adjusted Net Income and
Free Cash Flow.
Additionally, the Company filed an amended Form 10-Q for the
quarter ended March 31, 2020, originally filed with the Securities
Exchange Commission (the "SEC") on May 7, 2020. The filing corrects
a $160 million understatement of the full cost ceiling
impairment expense for the quarter ended March 31, 2020, which
caused an understatement of the balances of accumulated depletion
and impairment and accumulated deficit, and a corresponding
overstatement of the same amount to both net income and the balance
of our oil and natural gas properties as of March 31, 2020. This
error was isolated to the Company's first-quarter estimate of the
full cost impairment and had no impact on the Company's prior
financial statements, including the 2019 annual report on Form
10-K. This press release gives effect to the corrections to the
amounts included in the amended first quarter report. Please refer
to the Form 10-Q/A for the period ended March 31, 2020 and Form
8-K, both filed with the SEC on August 5, 2020, for additional
information.
Second-Quarter 2020 Highlights
- Received $86.9 million from settlements of matured commodity
derivatives, resulting in an average hedged sales price of $21.09
per barrel of oil equivalent ("BOE"), a 92% increase versus an
average unhedged sales price of $10.99 per BOE in the same
period
- Reduced unit lease operating expenses ("LOE") to $2.40 per BOE,
a 24% decrease from the second quarter of 2019
- Reduced unit general and administrative expenses ("G&A") to
$1.24 per BOE, a 16% decrease from the second quarter of 2019
- Produced an average of 31,241 barrels of oil per day ("BOPD"),
an increase of 3% from the second quarter of 2019
- Produced an average of 94,117 BOE per day, an increase of 14%
from the second quarter of 2019
"The macro environment during the second quarter of 2020 was
unprecedented in its difficulties for the energy industry," stated
Jason Pigott, President and Chief Executive Officer. "Our success
managing through this turbulence highlights the benefits of how we
run our business. We mitigate commodity price risk with a robust
hedging program, maintain operational flexibility and focus on
driving additional costs out of the business."
"We are excited to demonstrate the capital efficiency of our
Howard County acquisition as we resume development activities and
begin completions operations later in the third quarter," continued
Mr. Pigott. "As we expect to maintain a stable drilling and
completions cadence in 2021, we remain focused on operating within
cash flow and securing those cash flows with a consistent hedging
program. Steady completions activity in Howard County, combined
with increased commodity prices and hedges in 2021, supports an
estimated $120 million in additional cash flow in 2021 and should
return our oil production to full-year 2019 levels. In combination
with growing cash flows, our focus is on strengthening our balance
sheet as we evaluate acquisition and deleveraging opportunities and
improving our debt-to-equity ratio."
2020/2021 Operational Activity Levels
In early 2020, the Company significantly reduced planned
operational activities as commodity prices suffered from historic
declines amid COVID-19 related demand destruction and OPEC+ pricing
and supply decisions which dramatically reduced expected returns on
capital investments. A subsequent increase in commodity prices,
paired with service cost reductions, has driven expected returns on
Laredo's Howard County acreage back to levels that support a
resumption of activity. Beginning in September 2020, the Company
plans to operate a completions crew in Howard County.
Laredo now expects to complete a 15-well package in Howard
County during the fourth quarter of 2020. This additional activity
is expected to improve the Company's production beginning in the
first quarter of 2021. Laredo now anticipates capital expenditures
for full-year 2020 to be $340 - $350 million and to operate within
cash flow, excluding non-budgeted acquisitions.
At current service costs and commodity prices, the Company plans
to return to a normalized operational cadence of two rigs and one
completions crew at the beginning of 2021. This stable activity
level eliminates the disruptions associated with either
front-loading or halting completions during the year, drives
operational and capital efficiencies, and balances the number of
wells drilled with those completed. Planned activity in 2021 will
be focused on the Company's oily, high-return Howard County
acreage, with 50 - 55 completions anticipated in 2021.
Laredo expects this 2021 activity to be accomplished with total
capital expenditures of $325 - $350 million and to generate
full-year 2021 oil production of 27.0 - 29.0 MBOPD. To protect the
returns and cash flow associated with this development program, the
Company has entered into additional oil hedges and currently has
20,150 BOPD hedged for 2021 at a weighted-average Brent floor price
of $51 per barrel.
Operations Summary
During the second quarter of 2020, the Company completed 5 gross
(4.6 net) horizontal wells, all on its recently- acquired western
Glasscock acreage. Early production results were restrained by the
sizing of field infrastructure built by the previous operator.
After installing appropriately-sized flow lines for the five-well
package, artificial lift operations have been optimized and wells
are performing at or above initial productivity expectations.
Laredo produced 94,117 BOE per day in the second quarter of
2020, including oil production of 31,241 BOPD, exceeding the
high-end of guidance by 10% and 2%, respectively. Production
results were driven by the sustained outperformance of well
packages developed with the Company's area-specific optimized
spacing and completions design.
The Company is currently operating one drilling rig, located in
Howard County. A completions crew will be deployed to Howard County
late in the third quarter of 2020 and will begin completions
operations on a 15-well package. Based on current service costs,
well costs are expected to be $550 per lateral foot.
Unit LOE for second-quarter 2020 decreased to $2.40 per BOE, a
reduction of 14% from the first quarter of 2020. Production
expenses on the Company's established acreage position benefit from
Laredo's prior investments in field infrastructure and the use of
low-cost gas lift for artificial lift. As the Company transitions
to Howard County, unit LOE is expected to increase moderately as
utilization of ESP's for artificial lift is preferred to optimize
the oilier production from these wells. Unit LOE in Howard County
is expected to be approximately $4.00 per BOE, with combined unit
LOE for the Company expected to remain below $3.00 per BOE for
full-year 2021.
G&A Expenses
Laredo continues to focus on further improving the Company's
peer-leading cost structure. As previously announced, Laredo took
steps to preserve margins in this challenging commodity price
environment. A combination of an approximate 8% headcount
reduction, Company-wide salary reductions and a decrease in
Director's fees drove unit G&A to $1.24 per BOE. The Company
expects G&A expenses for full-year 2020 to be approximately 10%
less than full-year 2019 levels.
Second-Quarter 2020 Costs Incurred
During the second quarter of 2020, excluding non-budgeted
acquisitions, total costs incurred were $78 million, comprised of
$63 million in drilling and completions activities, $3 million in
land, exploration and data related costs, $6 million in
infrastructure, including Laredo Midstream Services investments,
and $6 million in other capitalized costs. Additionally, a
non-budgeted acquisition of $1 million was closed during the
quarter.
Increased Oil Hedges
The Company maintains an active, multi-year commodity and
interest rate derivatives strategy to manage commodity price risk
and support operating cash flows. Laredo utilizes only puts, swaps
and collars and does not enter into three-way collars, which limit
protection in a rapidly declining price environment.
For the remainder of 2020, Laredo has hedged 4.8 million barrels
of oil, with 3.6 million barrels of oil swapped at a
weighted-average price of $59.50 WTI per barrel and 1.2 million
barrels of oil swapped at a weighted-average price of $63.07 Brent
per barrel. For 2021, the Company has hedged approximately 70% of
expected oil production, with 7.4 million barrels of oil at a
weighted-average floor price of $51.11 Brent per barrel.
Please see the table in the appendix of Laredo's Second-Quarter
2020 Earnings Presentation posted to the Company's website for the
full details of the Company's commodity derivatives.
Liquidity
At June 30, 2020, the Company had outstanding borrowings of $275
million on its $725 million senior secured credit facility,
resulting in available capacity, after the reduction for
outstanding letters of credit, of $406 million. Including cash and
cash equivalents of $16 million, total liquidity was $422
million.
At August 4, 2020, the Company had outstanding borrowings of
$300 million on its $725 million senior secured credit facility,
resulting in available capacity, after the reduction for
outstanding letters of credit, of $381 million. Including cash and
cash equivalents of $21 million, total liquidity was $402
million.
Third-Quarter and Full-Year 2020 Guidance
The table below reflects the Company's quarterly and full-year
guidance for total and oil production for 2020.
|
|
3Q-20E |
|
4Q-20E |
|
FY-20E |
Total production (MBOE per
day) |
|
83.5 - 85.5 |
|
78.0 - 80.0 |
|
85.5 - 86.5 |
Oil production
(MBOPD) |
|
24.2 - 25.2 |
|
20.5 - 21.5 |
|
26.2 - 26.8 |
The table below reflects the Company's guidance for selected
revenue and expense items for the third quarter of 2020.
|
|
3Q-20E |
Average sales price
realizations (excluding derivatives): |
|
|
Oil (% of WTI) |
|
96% |
NGL (% of WTI) |
|
21% |
Natural gas (% of Henry Hub) |
|
54% |
|
|
|
Other ($ MM): |
|
|
Net income (expense) of purchased oil |
|
($4.5) |
Net midstream service income (expense) |
|
$1.2 |
|
|
|
Selected average costs &
expenses: |
|
|
Lease operating expenses ($/BOE) |
|
$2.75 |
Production and ad valorem taxes (% of oil, NGL and natural gas
sales revenues) |
|
7.25% |
Transportation and marketing expenses ($/BOE) |
|
$1.40 |
General and administrative expenses (excluding long-term incentive
plan ("LTIP"), $/BOE) |
|
$1.40 |
General and administrative expenses (LTIP cash and non-cash,
$/BOE) |
|
$0.45 |
Depletion, depreciation and amortization ($/BOE) |
|
$6.50 |
Conference Call Details
On Thursday, August 6, 2020, at 7:30 a.m. CT, Laredo will host a
conference call to discuss its second-quarter 2020 financial and
operating results and management's outlook, the content of which is
not part of this earnings release. A slide presentation providing
summary financial and statistical information that will be
discussed on the call will be posted to the Company's website and
available for review. The Company invites interested parties to
listen to the call via the Company's website at
www.laredopetro.com, under the tab for "Investor Relations."
Portfolio managers and analysts who would like to participate on
the call should dial 877.930.8286 (international dial-in
253.336.8309), using conference code 4172567, 10 minutes prior to
the scheduled conference time. A telephonic replay will be
available two hours after the call on August 6, 2020 through
Thursday, August 13, 2020. Participants may access this replay by
dialing 855.859.2056, using conference code 4172567.
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 StatementsThis 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. This press release and any accompanying
disclosures may include or reference certain forward-looking,
non-GAAP financial measures, such as Free Cash Flow, Adjusted Net
Income and Adjusted EBITDA, and certain related estimates regarding
future performance, results and financial position. The
forward-looking statements are based on management’s current
belief, based on currently available information, as to the outcome
and timing of future events. General risks relating to Laredo
include, but are not limited to, the decline in prices of oil,
natural gas liquids and natural gas and the related impact to
financial statements as a result of asset impairments and revisions
to reserve estimates, oil production quotas or other actions that
might be imposed by the Organization of Petroleum Exporting
Countries and other producing countries ("OPEC+"), the outbreak of
disease, such as the coronavirus ("COVID-19") pandemic, and any
related government policies and actions, changes in domestic and
global production, supply and demand for commodities, including as
a result of the COVID-19 pandemic and actions by OPEC+, long-term
performance of wells, drilling and operating risks, the increase in
service and supply costs, tariffs on steel, pipeline transportation
and storage constraints in the Permian Basin, the possibility of
production curtailment, hedging activities, possible impacts of
litigation and regulations, the impact of repurchases, if any, of
securities from time to time 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
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," and "type curve," 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 or 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, drilling results, 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,
our 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. 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.
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.
Unless otherwise specified, references to “average sales price”
refer to average sales price excluding the effects of our
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 June 30, |
|
Six months ended June 30, 2020 |
|
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Sales volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,843 |
|
|
2,771 |
|
|
5,498 |
|
|
5,305 |
|
NGL (MBbl) |
|
2,752 |
|
|
2,200 |
|
|
5,219 |
|
|
4,299 |
|
Natural gas (MMcf) |
|
17,817 |
|
|
15,092 |
|
|
34,329 |
|
|
27,941 |
|
Oil equivalents (MBOE)(1)(2) |
|
8,565 |
|
|
7,485 |
|
|
16,439 |
|
|
14,260 |
|
Average daily oil equivalent sales volumes (BOE/D)(2) |
|
94,117 |
|
|
82,259 |
|
|
90,324 |
|
|
78,787 |
|
Average daily oil sales volumes (BOPD)(2) |
|
31,241 |
|
|
30,447 |
|
|
30,209 |
|
|
29,308 |
|
Average sales prices(2): |
|
|
|
|
|
|
|
|
Oil ($/Bbl)(3) |
|
$ |
24.66 |
|
|
$ |
57.76 |
|
|
$ |
34.57 |
|
|
$ |
54.52 |
|
NGL ($/Bbl)(3) |
|
$ |
4.81 |
|
|
$ |
10.09 |
|
|
$ |
4.75 |
|
|
$ |
12.66 |
|
Natural gas ($/Mcf)(3) |
|
$ |
0.61 |
|
|
$ |
0.11 |
|
|
$ |
0.44 |
|
|
$ |
0.49 |
|
Average sales price ($/BOE)(3) |
|
$ |
10.99 |
|
|
$ |
24.56 |
|
|
$ |
13.99 |
|
|
$ |
25.05 |
|
Oil, with commodity derivatives ($/Bbl)(4) |
|
$ |
50.46 |
|
|
$ |
56.65 |
|
|
$ |
53.42 |
|
|
$ |
52.36 |
|
NGL, with commodity derivatives ($/Bbl)(4) |
|
$ |
7.60 |
|
|
$ |
12.82 |
|
|
$ |
7.24 |
|
|
$ |
14.04 |
|
Natural gas, with commodity derivatives ($/Mcf)(4) |
|
$ |
0.91 |
|
|
$ |
1.17 |
|
|
$ |
0.93 |
|
|
$ |
1.14 |
|
Average sales price, with commodity derivatives ($/BOE)(4) |
|
$ |
21.09 |
|
|
$ |
27.09 |
|
|
$ |
22.10 |
|
|
$ |
25.94 |
|
Selected average costs and
expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
2.40 |
|
|
$ |
3.16 |
|
|
$ |
2.59 |
|
|
$ |
3.24 |
|
Production and ad valorem taxes |
|
0.81 |
|
|
1.51 |
|
|
0.98 |
|
|
1.30 |
|
Transportation and marketing expenses |
|
1.31 |
|
|
0.65 |
|
|
1.50 |
|
|
0.68 |
|
Midstream service expenses |
|
0.10 |
|
|
0.08 |
|
|
0.12 |
|
|
0.15 |
|
General and administrative (excluding LTIP) |
|
1.02 |
|
|
1.62 |
|
|
1.17 |
|
|
1.86 |
|
Total selected operating expenses |
|
$ |
5.64 |
|
|
$ |
7.02 |
|
|
$ |
6.36 |
|
|
$ |
7.23 |
|
General and administrative (LTIP): |
|
|
|
|
|
|
|
|
LTIP cash |
|
$ |
0.05 |
|
|
$ |
(0.03 |
) |
|
$ |
0.04 |
|
|
$ |
— |
|
LTIP non-cash |
|
$ |
0.17 |
|
|
$ |
(0.12 |
) |
|
$ |
0.21 |
|
|
$ |
0.42 |
|
Depletion, depreciation and amortization |
|
$ |
7.77 |
|
|
$ |
8.78 |
|
|
$ |
7.78 |
|
|
$ |
9.03 |
|
_______________________________________________________________________________
(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
our commodity derivative transactions on our average sales prices.
Our 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 June 30, |
|
Six months ended June 30, 2020 |
(in thousands, except
per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL and natural gas sales |
|
$ |
94,143 |
|
|
$ |
183,863 |
|
|
$ |
230,028 |
|
|
$ |
357,239 |
|
Midstream service revenues |
|
2,281 |
|
|
2,610 |
|
|
4,964 |
|
|
5,493 |
|
Sales of purchased oil |
|
14,164 |
|
|
30,170 |
|
|
80,588 |
|
|
62,858 |
|
Total revenues |
|
110,588 |
|
|
216,643 |
|
|
315,580 |
|
|
425,590 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
20,591 |
|
|
23,632 |
|
|
42,631 |
|
|
46,241 |
|
Production and ad valorem taxes |
|
6,938 |
|
|
11,328 |
|
|
16,182 |
|
|
18,547 |
|
Transportation and marketing expenses |
|
11,181 |
|
|
4,891 |
|
|
24,725 |
|
|
9,650 |
|
Midstream service expenses |
|
815 |
|
|
607 |
|
|
1,985 |
|
|
2,210 |
|
Costs of purchased oil |
|
16,117 |
|
|
30,172 |
|
|
95,414 |
|
|
62,863 |
|
General and administrative |
|
10,659 |
|
|
11,056 |
|
|
23,221 |
|
|
32,575 |
|
Organizational restructuring expenses |
|
4,200 |
|
|
10,406 |
|
|
4,200 |
|
|
10,406 |
|
Depletion, depreciation and amortization |
|
66,574 |
|
|
65,703 |
|
|
127,876 |
|
|
128,801 |
|
Impairment expense |
|
406,448 |
|
|
— |
|
|
593,147 |
|
|
— |
|
Other operating expenses |
|
1,117 |
|
|
1,020 |
|
|
2,223 |
|
|
2,072 |
|
Total costs and expenses |
|
544,640 |
|
|
158,815 |
|
|
931,604 |
|
|
313,365 |
|
Operating income (loss) |
|
(434,052 |
) |
|
57,828 |
|
|
(616,024 |
) |
|
112,225 |
|
Non-operating income
(expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
(90,537 |
) |
|
88,394 |
|
|
207,299 |
|
|
40,029 |
|
Interest expense |
|
(27,072 |
) |
|
(15,765 |
) |
|
(52,042 |
) |
|
(31,312 |
) |
Litigation settlement |
|
— |
|
|
42,500 |
|
|
— |
|
|
42,500 |
|
Loss on extinguishment of debt |
|
— |
|
|
— |
|
|
(13,320 |
) |
|
— |
|
Other, net |
|
(967 |
) |
|
2,176 |
|
|
(1,478 |
) |
|
2,104 |
|
Total non-operating income (expense), net |
|
(118,576 |
) |
|
117,305 |
|
|
140,459 |
|
|
53,321 |
|
Income (loss) before income taxes |
|
(552,628 |
) |
|
175,133 |
|
|
(475,565 |
) |
|
165,546 |
|
Income tax benefit
(expense): |
|
|
|
|
|
|
|
|
Deferred |
|
7,173 |
|
|
(1,751 |
) |
|
4,756 |
|
|
(1,655 |
) |
Total income tax benefit (expense) |
|
7,173 |
|
|
(1,751 |
) |
|
4,756 |
|
|
(1,655 |
) |
Net income (loss) |
|
$ |
(545,455 |
) |
|
$ |
173,382 |
|
|
$ |
(470,809 |
) |
|
$ |
163,891 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(46.75 |
) |
|
$ |
14.99 |
|
|
$ |
(40.44 |
) |
|
$ |
14.19 |
|
Diluted |
|
$ |
(46.75 |
) |
|
$ |
14.98 |
|
|
$ |
(40.44 |
) |
|
$ |
14.15 |
|
Weighted-average common shares
outstanding(1): |
|
|
|
|
|
|
|
|
Basic |
|
11,667 |
|
|
11,570 |
|
|
11,642 |
|
|
11,547 |
|
Diluted |
|
11,667 |
|
|
11,578 |
|
|
11,642 |
|
|
11,586 |
|
_______________________________________________________________________________
(1) Net income (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 June 30, |
|
Six months ended June 30, 2020 |
(in
thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Cash flows from operating
activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(545,455 |
) |
|
$ |
173,382 |
|
|
$ |
(470,809 |
) |
|
$ |
163,891 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
1,694 |
|
|
(423 |
) |
|
4,070 |
|
|
6,983 |
|
Depletion, depreciation and amortization |
|
66,574 |
|
|
65,703 |
|
|
127,876 |
|
|
128,801 |
|
Impairment expense |
|
406,448 |
|
|
— |
|
|
593,147 |
|
|
— |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
90,537 |
|
|
(88,394 |
) |
|
(207,299 |
) |
|
(40,029 |
) |
Settlements received for matured derivatives, net |
|
86,872 |
|
|
23,480 |
|
|
134,595 |
|
|
23,582 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives |
|
(50,593 |
) |
|
(2,233 |
) |
|
(51,070 |
) |
|
(6,249 |
) |
Loss on extinguishment of debt |
|
— |
|
|
— |
|
|
13,320 |
|
|
— |
|
Deferred income tax (benefit) expense |
|
(7,173 |
) |
|
1,751 |
|
|
(4,756 |
) |
|
1,655 |
|
Other, net |
|
5,936 |
|
|
4,413 |
|
|
12,857 |
|
|
12,189 |
|
Cash flows from operating activities before changes in operating
assets and liabilities, net |
|
54,840 |
|
|
172,270 |
|
|
151,931 |
|
|
285,414 |
|
Change in current assets and liabilities, net |
|
8,750 |
|
|
9,628 |
|
|
27,458 |
|
|
(27,122 |
) |
Change in noncurrent assets and liabilities, net |
|
(1,617 |
) |
|
1,913 |
|
|
(7,827 |
) |
|
2,977 |
|
Net cash provided by operating activities |
|
61,973 |
|
|
183,811 |
|
|
171,562 |
|
|
261,269 |
|
Cash flows from investing
activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties, net |
|
(687 |
) |
|
(2,880 |
) |
|
(23,563 |
) |
|
(2,880 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(106,563 |
) |
|
(131,887 |
) |
|
(241,939 |
) |
|
(284,616 |
) |
Midstream service assets |
|
(1,000 |
) |
|
(3,187 |
) |
|
(1,761 |
) |
|
(5,449 |
) |
Other fixed assets |
|
(1,240 |
) |
|
(460 |
) |
|
(2,069 |
) |
|
(965 |
) |
Proceeds from dispositions of capital assets, net of selling
costs |
|
677 |
|
|
893 |
|
|
728 |
|
|
936 |
|
Net cash used in investing activities |
|
(108,813 |
) |
|
(137,521 |
) |
|
(268,604 |
) |
|
(292,974 |
) |
Cash flows from financing
activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
— |
|
|
— |
|
|
— |
|
|
80,000 |
|
Payments on Senior Secured Credit Facility |
|
— |
|
|
(35,000 |
) |
|
(100,000 |
) |
|
(35,000 |
) |
Issuance of January 2025 Notes and January 2028 Notes |
|
— |
|
|
— |
|
|
1,000,000 |
|
|
— |
|
Extinguishment of debt |
|
— |
|
|
— |
|
|
(808,855 |
) |
|
— |
|
Payments for debt issuance costs |
|
(68 |
) |
|
— |
|
|
(18,451 |
) |
|
— |
|
Other, net |
|
(122 |
) |
|
(34 |
) |
|
(762 |
) |
|
(2,646 |
) |
Net cash (used in) provided by financing activities |
|
(190 |
) |
|
(35,034 |
) |
|
71,932 |
|
|
42,354 |
|
Net (decrease) increase in
cash and cash equivalents |
|
(47,030 |
) |
|
11,256 |
|
|
(25,110 |
) |
|
10,649 |
|
Cash and cash equivalents,
beginning of period |
|
62,777 |
|
|
44,544 |
|
|
40,857 |
|
|
45,151 |
|
Cash and cash equivalents, end
of period |
|
$ |
15,747 |
|
|
$ |
55,800 |
|
|
$ |
15,747 |
|
|
$ |
55,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum,
Inc.Total Costs Incurred
The following tables present the components of our costs
incurred, excluding non-budgeted acquisition costs, for the periods
presented and corresponding changes:
|
|
Three months ended June 30, |
|
Six months ended June 30, 2020 |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas properties |
|
$ |
75,941 |
|
|
$ |
128,780 |
|
|
$ |
228,809 |
|
|
$ |
289,002 |
|
Midstream service assets |
|
671 |
|
|
3,064 |
|
|
1,594 |
|
|
6,437 |
|
Other fixed assets |
|
1,774 |
|
|
453 |
|
|
2,597 |
|
|
967 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
78,386 |
|
|
$ |
132,297 |
|
|
$ |
233,000 |
|
|
$ |
296,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 us, may not be comparable
to similarly titled measures used by other companies. Therefore,
these non-GAAP financial measures should be considered in
conjunction with net income or loss and other performance measures
prepared in accordance with GAAP, such as operating income or loss
or cash flows from operating activities. Free Cash Flow, Adjusted
Net Income and Adjusted EBITDA should not be considered in
isolation or as a substitute for GAAP measures, such as net income
or loss, operating income or loss or any other GAAP measure of
liquidity or financial performance.
Free Cash Flow (Unaudited)
Free Cash Flow, a non-GAAP financial measure, does not represent
funds available for future discretionary use because it excludes
funds required for future debt service, capital expenditures,
acquisitions, working capital, income taxes, franchise taxes and
other commitments and obligations. However, our management believes
Free Cash Flow is useful to management and investors in evaluating
operating trends in our business that are affected by production,
commodity prices, operating costs and other related factors. There
are significant limitations to the use of Free Cash Flow as a
measure of performance, including the lack of comparability due to
the different methods of calculating Free Cash Flow reported by
different companies.
The following table presents a reconciliation of net cash
provided by operating activities (GAAP) to cash flows from
operating activities before changes in operating assets and
liabilities, net, less costs incurred, excluding non-budgeted
acquisition costs, for the calculation of Free Cash Flow (non-GAAP)
for the periods presented:
|
|
Three months ended June 30, |
|
Six months ended June 30, 2020 |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating activities |
|
$ |
61,973 |
|
|
$ |
183,811 |
|
|
$ |
171,562 |
|
|
$ |
261,269 |
|
Less: |
|
|
|
|
|
|
|
|
Change in current assets and liabilities, net |
|
8,750 |
|
|
9,628 |
|
|
27,458 |
|
|
(27,122 |
) |
Change in noncurrent assets and liabilities, net |
|
(1,617 |
) |
|
1,913 |
|
|
(7,827 |
) |
|
2,977 |
|
Cash flows from operating
activities before changes in operating assets and liabilities,
net |
|
54,840 |
|
|
172,270 |
|
|
151,931 |
|
|
285,414 |
|
Less costs incurred, excluding non-budgeted acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas properties(1) |
|
75,941 |
|
|
128,780 |
|
|
228,809 |
|
|
289,002 |
|
Midstream service assets(1) |
|
671 |
|
|
3,064 |
|
|
1,594 |
|
|
6,437 |
|
Other fixed assets |
|
1,774 |
|
|
453 |
|
|
2,597 |
|
|
967 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
78,386 |
|
|
132,297 |
|
|
233,000 |
|
|
296,406 |
|
Free Cash Flow (non-GAAP) |
|
$ |
(23,546 |
) |
|
$ |
39,973 |
|
|
$ |
(81,069 |
) |
|
$ |
(10,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________________________________________________________________________
(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 we use to
evaluate performance, prior to income taxes, mark-to-market on
derivatives, premiums paid for commodity derivatives that matured
during the period, impairment expense, gains or losses on disposal
of assets and other non-recurring income and expenses and after
applying adjusted income tax expense. We believe Adjusted Net
Income helps investors in the oil and natural gas industry to
measure and compare our 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):
|
|
Three months ended June 30, |
|
Six months ended June 30, 2020 |
(in thousands, except
per share data) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Income (loss) before income
taxes |
|
$ |
(552,628 |
) |
|
$ |
175,133 |
|
|
$ |
(475,565 |
) |
|
$ |
165,546 |
|
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
90,537 |
|
|
(88,394 |
) |
|
(207,299 |
) |
|
(40,029 |
) |
Settlements received for matured derivatives, net |
|
86,872 |
|
|
23,480 |
|
|
134,595 |
|
|
23,582 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
(2,233 |
) |
|
(477 |
) |
|
(6,249 |
) |
Organizational restructuring expenses |
|
4,200 |
|
|
10,406 |
|
|
4,200 |
|
|
10,406 |
|
Impairment expense |
|
406,448 |
|
|
— |
|
|
593,147 |
|
|
— |
|
Loss on extinguishment of debt |
|
— |
|
|
— |
|
|
13,320 |
|
|
— |
|
Litigation settlement |
|
— |
|
|
(42,500 |
) |
|
— |
|
|
(42,500 |
) |
(Gain) loss on disposal of assets, net |
|
(152 |
) |
|
670 |
|
|
450 |
|
|
1,609 |
|
Write-off of debt issuance costs |
|
1,103 |
|
|
— |
|
|
1,103 |
|
|
— |
|
Adjusted income before adjusted income tax expense |
|
36,380 |
|
|
71,153 |
|
|
63,474 |
|
|
106,956 |
|
Adjusted income tax expense(2) |
|
(8,004 |
) |
|
(15,654 |
) |
|
(13,964 |
) |
|
(23,530 |
) |
Adjusted Net Income |
|
$ |
28,376 |
|
|
$ |
55,499 |
|
|
$ |
49,510 |
|
|
$ |
83,426 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(46.75 |
) |
|
$ |
14.99 |
|
|
$ |
(40.44 |
) |
|
$ |
14.19 |
|
Diluted |
|
$ |
(46.75 |
) |
|
$ |
14.98 |
|
|
$ |
(40.44 |
) |
|
$ |
14.15 |
|
Adjusted Net Income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.43 |
|
|
$ |
4.80 |
|
|
$ |
4.25 |
|
|
$ |
7.22 |
|
Diluted |
|
$ |
2.43 |
|
|
$ |
4.79 |
|
|
$ |
4.25 |
|
|
$ |
7.20 |
|
Adjusted diluted |
|
$ |
2.43 |
|
|
$ |
4.79 |
|
|
$ |
4.23 |
|
|
$ |
7.20 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
11,667 |
|
|
11,570 |
|
|
11,642 |
|
|
11,547 |
|
Diluted |
|
11,667 |
|
|
11,578 |
|
|
11,642 |
|
|
11,586 |
|
Adjusted diluted |
|
11,686 |
|
|
11,578 |
|
|
11,697 |
|
|
11,586 |
|
_______________________________________________________________________________
(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
June 30, 2020 and 2019.
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define
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, our management believes
Adjusted EBITDA is useful to an investor in evaluating our
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 our operations from period to period by removing the
effect of our capital structure from our operating structure;
and
- is used by our management for various purposes, including
as a measure of operating performance, in presentations to our
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 our 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. Our measurements of Adjusted EBITDA for financial
reporting as compared to compliance under our 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 June 30, |
|
Six months ended June 30, 2020 |
(in thousands) |
|
2020 |
|
2019 |
|
2020 |
|
2019 |
|
|
(unaudited) |
|
(unaudited) |
Net income (loss) |
|
$ |
(545,455 |
) |
|
$ |
173,382 |
|
|
$ |
(470,809 |
) |
|
$ |
163,891 |
|
Plus: |
|
|
|
|
|
|
|
|
Share-settled equity-based compensation, net |
|
1,694 |
|
|
(423 |
) |
|
4,070 |
|
|
6,983 |
|
Depletion, depreciation and amortization |
|
66,574 |
|
|
65,703 |
|
|
127,876 |
|
|
128,801 |
|
Impairment expense |
|
406,448 |
|
|
— |
|
|
593,147 |
|
|
— |
|
Organizational restructuring expenses |
|
4,200 |
|
|
10,406 |
|
|
4,200 |
|
|
10,406 |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
90,537 |
|
|
(88,394 |
) |
|
(207,299 |
) |
|
(40,029 |
) |
Settlements received for matured derivatives, net |
|
86,872 |
|
|
23,480 |
|
|
134,595 |
|
|
23,582 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
(5,409 |
) |
|
— |
|
|
(5,409 |
) |
Premiums paid for commodity derivatives that matured during the
period(1) |
|
— |
|
|
(2,233 |
) |
|
(477 |
) |
|
(6,249 |
) |
Accretion expense |
|
1,117 |
|
|
1,020 |
|
|
2,223 |
|
|
2,072 |
|
(Gain) loss on disposal of assets, net |
|
(152 |
) |
|
670 |
|
|
450 |
|
|
1,609 |
|
Interest expense |
|
27,072 |
|
|
15,765 |
|
|
52,042 |
|
|
31,312 |
|
Loss on extinguishment of debt |
|
— |
|
|
— |
|
|
13,320 |
|
|
— |
|
Litigation settlement |
|
— |
|
|
(42,500 |
) |
|
— |
|
|
(42,500 |
) |
Write-off of debt issuance costs |
|
1,103 |
|
|
— |
|
|
1,103 |
|
|
— |
|
Income tax (benefit) expense |
|
(7,173 |
) |
|
1,751 |
|
|
(4,756 |
) |
|
1,655 |
|
Adjusted EBITDA |
|
$ |
132,837 |
|
|
$ |
153,218 |
|
|
$ |
249,685 |
|
|
$ |
276,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________________________________________________________________________
(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.
Forecasted Free Cash FlowForecasted Free Cash
Flow, a non-GAAP financial measure, is calculated as estimated cash
flows from operating activities before changes in assets and
liabilities, less estimated costs incurred, excluding non-budgeted
acquisition costs, made during the period. Management believes this
is useful to management and investors in evaluating the operating
trends in its business due to production, commodity prices,
operating costs and other related factors. We do not provide
guidance on the reconciling items between forecasted cash provided
by operating activities and forecasted Free Cash Flow due to the
uncertainty regarding timing and estimates of these items.
Therefore, we cannot reconcile forecasted cash provided by
operating activities to forecasted Free Cash Flow without
unreasonable effort.
Contact:Ron Hagood: (918) 858-5504 -
RHagood@laredopetro.com
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