Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its fourth-quarter and full-year 2019 results. For
the fourth quarter of 2019, the Company reported a net loss
attributable to common stockholders of $241.7 million, or $1.04 per
diluted share, which includes a non-cash full cost ceiling
impairment charge of $222.7 million. Adjusted Net Income, a
non-GAAP financial measure, for the fourth quarter of 2019 was
$39.7 million, or $0.17 per adjusted diluted share. Adjusted
EBITDA, a non-GAAP financial measure, for the fourth quarter of
2019 was $137.9 million.
For full-year 2019, the Company reported a net loss attributable
to common stockholders of $342.5 million, or $1.48 per diluted
share, which includes a non-cash full cost ceiling impairment
charge of $620.6 million. Adjusted Net Income for full-year 2019
was $172.0 million, or $0.74 per adjusted diluted share and
Adjusted EBITDA was $560.2 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.
2019 Full-Year Highlights
- Generated $475.1 million of net cash provided by operating
activities and $59.7 million of Free Cash Flow in 2019 as the
Company reduced capital expenditures by 25% from full-year
2018
- Executed two accretive acquisitions of high-margin, oily
inventory at valuations significantly below historic averages while
maintaining a competitive leverage ratio
- Produced 28,429 barrels of oil per day ("BOPD") and 80,883
barrels of oil equivalent ("BOE") per day, increases of 2% and 19%,
respectively, from full-year 2018
- Grew total proved reserves by 55 million BOE and proved oil
reserves by 17 million barrels, increases of 23% and 27%,
respectively, versus year-end 2018
- Drove well costs down to $6.6 million for a 10,000-foot lateral
with the Company's standard completion design, a decrease from $7.7
million at year-end 2018
- Reduced controllable cash costs of combined unit lease
operating expenses ("LOE") and unit cash general and administrative
expenses ("G&A") to $4.65 per BOE, a 23% decrease from
full-year 2018 results of $6.07 per BOE
- Received net cash of $48.7 million on settlements of
derivatives, as the Company's hedges mitigated the impact of
commodity price declines
"During 2019, we successfully completed our transition to a
returns-focused, free-cash-flow-oriented strategy," stated Jason
Pigott, President and Chief Executive Officer. "We substantially
improved well productivity, aligned staffing with our moderated
development plan and continued to drive down both our well costs
and operational expenses. Our strong performance in all facets of
the business drove improved capital efficiency and Free Cash Flow
generation of approximately $60 million for full-year 2019."
"We leveraged our strengths to complete two accretive
acquisitions in oilier areas of the Midland Basin," continued Mr.
Pigott. "By deploying our proven operational expertise on acreage
with higher oil content, we expect to further improve margins and
capital efficiency and drive our oil mix above 40% by 2022. Our
development program over the next three years is designed to
maintain production levels, generate positive Projected Free Cash
Flow at $50 per barrel and deliver more than $100 million in
Projected Free Cash Flow at $55 per barrel."
"Financially, we are well positioned to continue delivering on
our returns-focused strategy. In January of 2020, we
opportunistically refinanced our senior unsecured notes, extending
our maturities to 2025 and 2028. For 2020, we have hedged a
substantial portion of our expected production at prices well above
current levels. Laredo is committed to maintaining its financial
strength, improving inventory quality and utilizing Free Cash Flow
to reduce debt."
E&P Update
During the fourth quarter of 2019, Laredo completed 15 gross
(13.1 net) horizontal wells, all on the Company's wider spacing
development plan, with an average completed lateral length of 9,900
feet. Drilling and completion cost incurred of $97 million was
in-line with expectations, even with one additional completion, as
the Company achieved performance records for both feet drilled and
completed feet per day.
In the fourth quarter of 2019, the Company exceeded both oil and
total production expectations for the fourth consecutive quarter.
Oil production of 27,296 BOPD beat guidance by 5% and total
production of 83,968 BOE per day beat guidance by 10%. The primary
driver of oil production exceeding expectations during the quarter
was the outperformance of the nine-well Sugg/Von Gonten package.
This package is currently exceeding the Company's Upper/Middle
Wolfcamp oil type curve by 39%.
In the first quarter of 2020, Laredo expects to complete 28
gross (27.7 net) widely-spaced horizontal wells with an average
completed lateral length of 8,500 feet. All anticipated
first-quarter 2020 completions are on the Company's established
acreage in Reagan and Glasscock counties. The Company is currently
operating two completion crews and expects to reduce activity to
one completion crew by the end of March 2020 as completion
activities transition to the newly acquired acreage in Howard and
Glasscock counties in the second quarter of 2020.
Howard County Update
Laredo's transition to its recently acquired Howard County
position is moving forward as planned. Two of the Company's four
drilling rigs have been deployed to Howard County and a third is
expected early in March 2020. The first well of Laredo's first
15-well package in Howard County has been successfully drilled and
completion operations are expected to commence on the full package
during the second quarter of 2020. Additionally, the Company is in
negotiations with multiple third-party providers of oil, natural
gas and water infrastructure services and does not expect costs for
these services to be significantly different from those on the
Company's established acreage base.
In early-February 2020, Laredo executed a bolt-on transaction to
its tier-one Howard County position, adding 1,100 net acres for
$22.5 million. The acquisition increases the Company's working
interest on its operated acreage from 83% to 96%, bringing Laredo's
Howard County leasehold to 8,380 net acres (99% operated). The
transaction increases the Company's operated inventory in Howard
County to 130 gross (124 net) primary locations in the Lower
Spraberry, Upper Wolfcamp and Middle Wolfcamp formations.
2019 Capital Program
During the fourth quarter of 2019, excluding non-budgeted
acquisitions, total costs incurred were $107 million, comprised of
$97 million in drilling and completions activities, $2 million in
land and data related costs, $2 million in infrastructure,
including Laredo Midstream Services investments, and $6 million in
other capitalized costs.
Total costs incurred of $482 million for full-year 2019,
excluding non-budgeted acquisitions, was below the Company's $490
million capital budget. For full-year 2019, Laredo delivered
approximately $60 million in Free Cash Flow, excluding non-budgeted
acquisitions.
Commodity Derivatives
For full-year 2020, the Company has hedged 9.6 million barrels
of oil, including 7.2 million barrels at $59.50 WTI and 2.4 million
barrels at $63.07 Brent, and 23.8 million MMBtu of natural gas at
$2.72 per MMBtu Henry Hub. Combined, Laredo's commodity derivatives
are expected to generate $152 million of positive cash flow at $50
per barrel WTI and $2.25 per MMBtu Henry Hub.
Liquidity
At December 31, 2019, the Company had outstanding borrowings of
$375 million on its $1.0 billion senior secured credit facility,
resulting in available capacity, after the reduction for
outstanding letters of credit, of $610 million. Including cash and
cash equivalents of $41 million, total liquidity was $651
million.
In January 2020, Laredo issued $1.0 billion of new senior
unsecured notes with the net proceeds to be used to redeem its
existing $800 million of outstanding senior unsecured notes and to
partially repay its senior secured credit facility. To date, the
Company has redeemed $749.4 million of the existing notes and has
issued call notices for the remaining $50.6 million. In conjunction
with the closing of the notes issuance, the Company's borrowing
base under its senior secured credit facility was reduced to
approximately $950 million.
At February 11, 2020, the Company had outstanding
borrowings of $275 million on its senior secured credit facility,
resulting in available capacity, after reductions for outstanding
letters of credit, of $660 million. Including cash and cash
equivalents of $67 million, net of expected cash to be used to
redeem the remaining March 2023 Notes, total liquidity was $727
million.
First-Quarter 2020 Guidance
|
1Q-2020E |
Total production (MBOE per
day) |
81.2 - 81.7 |
Oil production (MBOPD) |
26.8 -
27.3 |
|
|
Average sales price
realizations (excluding derivatives): |
|
Oil (% of WTI) |
100% |
NGL (% of WTI) |
14% |
Natural gas (% of Henry Hub) |
13% |
|
|
Other ($ MM): |
|
Net income / (expense) of
purchased crude oil |
($4.0) |
Net midstream income /
(expense) |
$1.5 |
|
|
Selected average costs &
expenses: |
|
Lease operating expenses ($/BOE) |
$3.00 |
Production and ad valorem taxes (% of oil, NGL and natural gas
revenues) |
6.50% |
Transportation and marketing expenses ($/BOE) |
$2.15 |
General and administrative: |
|
Cash ($/BOE) |
$1.60 |
Non-cash stock-based compensation, net ($/BOE) |
$0.55 |
Depletion, depreciation and amortization ($/BOE) |
$9.00 |
Conference Call Details
On Thursday, February 13, 2020, at 7:30 a.m. CT, Laredo will
host a conference call to discuss its fourth-quarter and full-year
2019 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 2388743, 10 minutes prior to
the scheduled conference time. A telephonic replay will be
available two hours after the call on February 13, 2020 through
Thursday, February 20, 2020. Participants may access this replay by
dialing 855.859.2056, using conference code 2388743.
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
subject 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, 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, long-term
performance of wells, drilling and operating risks, the increase in
service and supply costs, tariffs on steel, pipeline transportation
constraints in the Permian Basin, hedging activities, possible
impacts of litigation and regulations and other factors, including
those and other risks described in its Annual Report on Form 10-K
for the year ended December 31, 2018, and those set forth from time
to time in other filings with the Securities and Exchange
Commission ("SEC") including, but not limited to, its Annual Report
on Form 10-K for the year ended December 31, 2019, to be filed 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. Laredo does not
intend to, and disclaims any obligation to, update or revise any
forward-looking statement. Any forward-looking statement speaks
only as of the date on which such statement is made and the Company
undertakes no obligation to correct or update 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"
and "estimated ultimate recovery," "type curve" or "EURs," 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%. The 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 December 31, |
|
Year ended December 31, 2019 |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Sales volumes: |
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
2,511 |
|
|
2,571 |
|
|
10,376 |
|
|
10,175 |
|
NGL (MBbl) |
|
2,475 |
|
|
1,931 |
|
|
9,118 |
|
|
7,259 |
|
Natural gas (MMcf) |
|
16,438 |
|
|
11,983 |
|
|
60,169 |
|
|
44,680 |
|
Oil equivalents (MBOE)(1)(2) |
|
7,725 |
|
|
6,500 |
|
|
29,522 |
|
|
24,881 |
|
Average daily oil equivalent sales volumes (BOE/D)(2) |
|
83,968 |
|
|
70,653 |
|
|
80,883 |
|
|
68,168 |
|
Average daily oil sales volumes (Bbl/D)(2) |
|
27,296 |
|
|
27,949 |
|
|
28,429 |
|
|
27,878 |
|
Average sales prices(2): |
|
|
|
|
|
|
|
|
Oil ($/Bbl)(3) |
|
$ |
56.55 |
|
|
$ |
52.59 |
|
|
$ |
55.21 |
|
|
$ |
59.48 |
|
NGL ($/Bbl)(3) |
|
$ |
10.26 |
|
|
$ |
17.53 |
|
|
$ |
11.00 |
|
|
$ |
20.64 |
|
Natural gas ($/Mcf)(3) |
|
$ |
0.74 |
|
|
$ |
0.63 |
|
|
$ |
0.55 |
|
|
$ |
1.20 |
|
Average sales price ($/BOE)(3) |
|
$ |
23.24 |
|
|
$ |
27.18 |
|
|
$ |
23.93 |
|
|
$ |
32.50 |
|
Oil, with commodity derivatives ($/Bbl)(4) |
|
$ |
56.79 |
|
|
$ |
49.55 |
|
|
$ |
54.37 |
|
|
$ |
55.49 |
|
NGL, with commodity derivatives ($/Bbl)(4) |
|
$ |
13.02 |
|
|
$ |
17.47 |
|
|
$ |
13.61 |
|
|
$ |
20.03 |
|
Natural gas, with commodity derivatives ($/Mcf)(4) |
|
$ |
0.94 |
|
|
$ |
1.74 |
|
|
$ |
1.05 |
|
|
$ |
1.77 |
|
Average sales price, with commodity derivatives
($/BOE)(4) |
|
$ |
24.62 |
|
|
$ |
28.01 |
|
|
$ |
25.45 |
|
|
$ |
31.72 |
|
Average selected costs and
expenses per BOE sold(2): |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
2.84 |
|
|
$ |
3.51 |
|
|
$ |
3.08 |
|
|
$ |
3.67 |
|
Production and ad valorem taxes |
|
1.43 |
|
|
1.73 |
|
|
1.38 |
|
|
1.99 |
|
Transportation and marketing expenses |
|
1.32 |
|
|
0.79 |
|
|
0.86 |
|
|
0.47 |
|
Midstream service expenses |
|
0.14 |
|
|
0.16 |
|
|
0.15 |
|
|
0.12 |
|
General and administrative: |
|
|
|
|
|
|
|
|
Cash |
|
1.33 |
|
|
2.08 |
|
|
1.57 |
|
|
2.40 |
|
Non-cash stock-based compensation, net(5) |
|
0.39 |
|
|
1.18 |
|
|
0.28 |
|
|
1.46 |
|
Depletion, depreciation and amortization |
|
8.78 |
|
|
9.29 |
|
|
9.00 |
|
|
8.55 |
|
Total selected costs and expenses |
|
$ |
16.23 |
|
|
$ |
18.74 |
|
|
$ |
16.32 |
|
|
$ |
18.66 |
|
Average cash margins per BOE
sold(2)(6): |
|
|
|
|
|
|
|
|
Without derivatives |
|
$ |
16.18 |
|
|
$ |
18.91 |
|
|
$ |
16.89 |
|
|
$ |
23.85 |
|
With commodity derivatives |
|
$ |
17.56 |
|
|
$ |
19.74 |
|
|
$ |
18.41 |
|
|
$ |
23.07 |
|
_______________________________________________________________________________
(1) BOE is calculated using a conversion rate of six Mcf per one
Bbl. (2) The numbers presented are based on actual amounts and
are not calculated using the rounded numbers presented in the table
above. (3) Price reflects the average of actual sales prices
received when control passes to the purchaser/customer adjusted for
quality, 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. (5) For the year ended December 31, 2019,
non-cash stock-based compensation, net, excluding forfeitures
related to our organizational restructuring, on a per BOE sold
basis was $0.66. (6) For each period presented, on a per
BOE sold basis, average cash margin is calculated as average sales
price less (i) lease operating expenses, (ii) production and ad
valorem taxes, (iii) transportation and marketing expenses, (iv)
midstream service expenses and (v) cash general and
administrative.
Laredo Petroleum,
Inc.Condensed consolidated statements of
operations
|
|
Three months ended December 31, |
|
Year ended December 31, 2019 |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Revenues: |
|
|
|
|
|
|
|
|
Oil, NGL and natural gas sales |
|
$ |
179,558 |
|
|
$ |
176,671 |
|
|
$ |
706,548 |
|
|
$ |
808,530 |
|
Midstream service revenues |
|
3,356 |
|
|
2,397 |
|
|
11,928 |
|
|
8,987 |
|
Sales of purchased oil |
|
35,208 |
|
|
36,219 |
|
|
118,805 |
|
|
288,258 |
|
Total revenues |
|
218,122 |
|
|
215,287 |
|
|
837,281 |
|
|
1,105,775 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
21,948 |
|
|
22,823 |
|
|
90,786 |
|
|
91,289 |
|
Production and ad valorem taxes |
|
11,080 |
|
|
11,225 |
|
|
40,712 |
|
|
49,457 |
|
Transportation and marketing expenses |
|
10,164 |
|
|
5,134 |
|
|
25,397 |
|
|
11,704 |
|
Midstream service expenses |
|
1,085 |
|
|
1,048 |
|
|
4,486 |
|
|
2,872 |
|
Costs of purchased oil |
|
39,034 |
|
|
36,222 |
|
|
122,638 |
|
|
288,674 |
|
General and administrative |
|
13,302 |
|
|
21,182 |
|
|
54,729 |
|
|
96,138 |
|
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
16,371 |
|
|
— |
|
Depletion, depreciation and amortization |
|
67,846 |
|
|
60,399 |
|
|
265,746 |
|
|
212,677 |
|
Impairment expense |
|
222,999 |
|
|
— |
|
|
620,889 |
|
|
— |
|
Other operating expenses |
|
1,041 |
|
|
1,131 |
|
|
4,118 |
|
|
4,472 |
|
Total costs and expenses |
|
388,499 |
|
|
159,164 |
|
|
1,245,872 |
|
|
757,283 |
|
Operating income (loss) |
|
(170,377 |
) |
|
56,123 |
|
|
(408,591 |
) |
|
348,492 |
|
Non-operating income
(expense): |
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, net |
|
(57,562 |
) |
|
112,195 |
|
|
79,151 |
|
|
42,984 |
|
Interest expense |
|
(15,044 |
) |
|
(15,117 |
) |
|
(61,547 |
) |
|
(57,904 |
) |
Litigation settlement |
|
— |
|
|
— |
|
|
42,500 |
|
|
— |
|
Other, net |
|
(514 |
) |
|
(766 |
) |
|
3,440 |
|
|
(4,728 |
) |
Total non-operating income (expense), net |
|
(73,120 |
) |
|
96,312 |
|
|
63,544 |
|
|
(19,648 |
) |
Income (loss) before income taxes |
|
(243,497 |
) |
|
152,435 |
|
|
(345,047 |
) |
|
328,844 |
|
Income tax benefit
(expense): |
|
|
|
|
|
|
|
|
Current |
|
— |
|
|
426 |
|
|
— |
|
|
807 |
|
Deferred |
|
1,776 |
|
|
(3,288 |
) |
|
2,588 |
|
|
(5,056 |
) |
Total income tax benefit (expense) |
|
1,776 |
|
|
(2,862 |
) |
|
2,588 |
|
|
(4,249 |
) |
Net income (loss) |
|
$ |
(241,721 |
) |
|
$ |
149,573 |
|
|
$ |
(342,459 |
) |
|
$ |
324,595 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.04 |
) |
|
$ |
0.65 |
|
|
$ |
(1.48 |
) |
|
$ |
1.40 |
|
Diluted |
|
$ |
(1.04 |
) |
|
$ |
0.65 |
|
|
$ |
(1.48 |
) |
|
$ |
1.39 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,718 |
|
|
229,700 |
|
|
231,295 |
|
|
232,339 |
|
Diluted |
|
231,718 |
|
|
230,190 |
|
|
231,295 |
|
|
233,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum,
Inc.Condensed consolidated statements of cash
flows
|
|
Three months ended December 31, |
|
Year ended December 31, 2019 |
|
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Cash flows from operating
activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(241,721 |
) |
|
$ |
149,573 |
|
|
$ |
(342,459 |
) |
|
$ |
324,595 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Non-cash stock-based compensation, net |
|
3,046 |
|
|
7,648 |
|
|
8,290 |
|
|
36,396 |
|
Depletion, depreciation and amortization |
|
67,846 |
|
|
60,399 |
|
|
265,746 |
|
|
212,677 |
|
Impairment expense |
|
222,999 |
|
|
— |
|
|
620,889 |
|
|
— |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
57,562 |
|
|
(112,195 |
) |
|
(79,151 |
) |
|
(42,984 |
) |
Settlements received for matured commodity derivatives,
net |
|
14,394 |
|
|
12,033 |
|
|
63,221 |
|
|
6,090 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for commodity derivatives |
|
(1,399 |
) |
|
(5,405 |
) |
|
(9,063 |
) |
|
(20,335 |
) |
Deferred income tax (benefit) expense |
|
(1,776 |
) |
|
3,288 |
|
|
(2,588 |
) |
|
5,056 |
|
Other, net |
|
6,996 |
|
|
3,544 |
|
|
21,791 |
|
|
15,882 |
|
Cash flows from operating activities before changes in operating
assets and liabilities, net |
|
127,947 |
|
|
118,885 |
|
|
541,267 |
|
|
537,377 |
|
Change in current assets and liabilities, net |
|
(15,818 |
) |
|
10,842 |
|
|
(64,123 |
) |
|
1,157 |
|
Change in noncurrent assets and liabilities, net |
|
(3,923 |
) |
|
(451 |
) |
|
(2,070 |
) |
|
(730 |
) |
Net cash provided by operating activities |
|
108,206 |
|
|
129,276 |
|
|
475,074 |
|
|
537,804 |
|
Cash flows from investing
activities: |
|
|
|
|
|
|
|
|
Acquisitions of oil and natural gas properties, net of closing
adjustments |
|
(196,404 |
) |
|
(1,198 |
) |
|
(199,284 |
) |
|
(17,538 |
) |
Capital expenditures: |
|
|
|
|
|
|
|
|
Oil and natural gas properties |
|
(90,803 |
) |
|
(151,114 |
) |
|
(458,985 |
) |
|
(673,584 |
) |
Midstream service assets |
|
(1,169 |
) |
|
(1,020 |
) |
|
(7,910 |
) |
|
(6,784 |
) |
Other fixed assets |
|
(713 |
) |
|
(1,363 |
) |
|
(2,433 |
) |
|
(7,308 |
) |
Proceeds from dispositions of capital assets, net of selling
costs |
|
54 |
|
|
170 |
|
|
6,901 |
|
|
14,258 |
|
Net cash used in investing activities |
|
(289,035 |
) |
|
(154,525 |
) |
|
(661,711 |
) |
|
(690,956 |
) |
Cash flows from financing
activities: |
|
|
|
|
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
195,000 |
|
|
20,000 |
|
|
275,000 |
|
|
210,000 |
|
Payments on Senior Secured Credit Facility |
|
(5,000 |
) |
|
— |
|
|
(90,000 |
) |
|
(20,000 |
) |
Share repurchases |
|
— |
|
|
— |
|
|
— |
|
|
(97,055 |
) |
Other, net |
|
(7 |
) |
|
(7 |
) |
|
(2,657 |
) |
|
(6,801 |
) |
Net cash provided by financing activities |
|
189,993 |
|
|
19,993 |
|
|
182,343 |
|
|
86,144 |
|
Net increase (decrease) in
cash and cash equivalents |
|
9,164 |
|
|
(5,256 |
) |
|
(4,294 |
) |
|
(67,008 |
) |
Cash and cash equivalents,
beginning of period |
|
31,693 |
|
|
50,407 |
|
|
45,151 |
|
|
112,159 |
|
Cash and cash equivalents, end
of period |
|
$ |
40,857 |
|
|
$ |
45,151 |
|
|
$ |
40,857 |
|
|
$ |
45,151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum,
Inc.Total Costs Incurred
The following table presents the components of our costs
incurred, excluding non-budgeted acquisition costs:
|
|
Three months ended December 31, |
|
Year ended December 31, 2019 |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Oil and natural gas properties |
|
$ |
104,616 |
|
|
$ |
145,345 |
|
|
$ |
470,455 |
|
|
$ |
631,674 |
|
Midstream service assets |
|
1,071 |
|
|
969 |
|
|
8,655 |
|
|
4,618 |
|
Other fixed assets |
|
504 |
|
|
1,125 |
|
|
2,470 |
|
|
7,322 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
$ |
106,191 |
|
|
$ |
147,439 |
|
|
$ |
481,580 |
|
|
$ |
643,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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):
|
|
Three months ended December 31, |
|
Year ended December 31, 2019 |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
(unaudited) |
|
(unaudited) |
Net cash provided by operating activities |
|
$ |
108,206 |
|
|
$ |
129,276 |
|
|
$ |
475,074 |
|
|
$ |
537,804 |
|
Less: |
|
|
|
|
|
|
|
|
(Increase) decrease in current assets and liabilities, net |
|
(15,818 |
) |
|
10,842 |
|
|
(64,123 |
) |
|
1,157 |
|
Increase in noncurrent assets and liabilities, net |
|
(3,923 |
) |
|
(451 |
) |
|
(2,070 |
) |
|
(730 |
) |
Cash flows from operating
activities before changes in operating assets and liabilities,
net |
|
127,947 |
|
|
118,885 |
|
|
541,267 |
|
|
537,377 |
|
Less costs incurred, excluding non-budgeted acquisition costs: |
|
|
|
|
|
|
|
|
Oil and natural gas properties(1) |
|
$ |
104,616 |
|
|
$ |
145,345 |
|
|
$ |
470,455 |
|
|
$ |
631,674 |
|
Midstream service assets |
|
1,071 |
|
|
969 |
|
|
8,655 |
|
|
4,618 |
|
Other fixed assets |
|
504 |
|
|
1,125 |
|
|
2,470 |
|
|
7,322 |
|
Total costs incurred, excluding non-budgeted acquisition costs |
|
106,191 |
|
|
147,439 |
|
|
481,580 |
|
|
643,614 |
|
Free Cash Flow (non-GAAP) |
|
$ |
21,756 |
|
|
$ |
(28,554 |
) |
|
$ |
59,687 |
|
|
$ |
(106,237 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
_____________________________________________________________________________
(1) Includes non-cash stock-based compensation, net of $1.3
million and $1.9 million for the three months ended December 31,
2019 and 2018, respectively, and $4.5 million and $7.9 million for
the years ended December 31, 2019 and 2018, respectively.
Additionally, includes asset retirement costs of $0.1 million and
$0.2 million for the three months ended December 31, 2019 and 2018,
respectively, and $0.6 million and $0.7 million for the years ended
December 31, 2019 and 2018, respectively.
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 derivatives, 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 December 31, |
|
Year ended December 31, 2019 |
(in thousands, except per share data) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Income (loss) before income taxes |
|
$ |
(243,497 |
) |
|
$ |
152,435 |
|
|
$ |
(345,047 |
) |
|
$ |
328,844 |
|
Plus: |
|
|
|
|
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
57,562 |
|
|
(112,195 |
) |
|
(79,151 |
) |
|
(42,984 |
) |
Settlements received for matured commodity derivatives,
net |
|
14,394 |
|
|
12,033 |
|
|
63,221 |
|
|
6,090 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for commodity derivatives |
|
(1,399 |
) |
|
(5,405 |
) |
|
(9,063 |
) |
|
(20,335 |
) |
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
16,371 |
|
|
— |
|
Impairment expense |
|
222,999 |
|
|
— |
|
|
620,889 |
|
|
— |
|
Litigation settlement |
|
— |
|
|
— |
|
|
(42,500 |
) |
|
— |
|
(Gain) loss on disposal of assets, net |
|
(67 |
) |
|
1,207 |
|
|
248 |
|
|
5,798 |
|
Write-off of debt issuance costs |
|
935 |
|
|
— |
|
|
935 |
|
|
— |
|
Adjusted income before adjusted income tax expense |
|
50,927 |
|
|
48,075 |
|
|
220,494 |
|
|
277,413 |
|
Adjusted income tax expense(1) |
|
(11,204 |
) |
|
(10,577 |
) |
|
(48,509 |
) |
|
(61,031 |
) |
Adjusted Net Income |
|
$ |
39,723 |
|
|
$ |
37,498 |
|
|
$ |
171,985 |
|
|
$ |
216,382 |
|
Net income (loss) per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.04 |
) |
|
$ |
0.65 |
|
|
$ |
(1.48 |
) |
|
$ |
1.40 |
|
Diluted |
|
$ |
(1.04 |
) |
|
$ |
0.65 |
|
|
$ |
(1.48 |
) |
|
$ |
1.39 |
|
Adjusted Net Income per common
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.17 |
|
|
$ |
0.16 |
|
|
$ |
0.74 |
|
|
$ |
0.93 |
|
Diluted |
|
$ |
0.17 |
|
|
$ |
0.16 |
|
|
$ |
0.74 |
|
|
$ |
0.93 |
|
Adjusted diluted |
|
$ |
0.17 |
|
|
$ |
0.16 |
|
|
$ |
0.74 |
|
|
$ |
0.93 |
|
Weighted-average common shares
outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
231,718 |
|
|
229,700 |
|
|
231,295 |
|
|
232,339 |
|
Diluted |
|
231,718 |
|
|
230,190 |
|
|
231,295 |
|
|
233,172 |
|
Adjusted diluted |
|
231,828 |
|
|
230,190 |
|
|
231,897 |
|
|
233,172 |
|
_______________________________________________________________________________
(1) Adjusted income tax expense is calculated by applying a
statutory tax rate of 22% for each of the periods ended
December 31, 2019 and 2018.
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define
as net income or loss plus adjustments for non-cash stock-based
compensation, net, depletion, depreciation and amortization,
impairment expense, mark-to-market on derivatives, premiums paid
for commodity derivatives, accretion expense, gains or losses on
disposal of assets, write-off of debt issuance costs, 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 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):
|
|
Three months ended December 31, |
|
Year ended December 31, 2019 |
(in thousands) |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
(unaudited) |
|
(unaudited) |
Net income (loss) |
|
$ |
(241,721 |
) |
|
$ |
149,573 |
|
|
$ |
(342,459 |
) |
|
$ |
324,595 |
|
Plus: |
|
|
|
|
|
|
|
|
Non-cash stock-based compensation, net |
|
3,046 |
|
|
7,648 |
|
|
8,290 |
|
|
36,396 |
|
Depletion, depreciation and amortization |
|
67,846 |
|
|
60,399 |
|
|
265,746 |
|
|
212,677 |
|
Impairment expense |
|
222,999 |
|
|
— |
|
|
620,889 |
|
|
— |
|
Mark-to-market on derivatives: |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives, net |
|
57,562 |
|
|
(112,195 |
) |
|
(79,151 |
) |
|
(42,984 |
) |
Settlements received for matured commodity derivatives,
net |
|
14,394 |
|
|
12,033 |
|
|
63,221 |
|
|
6,090 |
|
Settlements paid for early terminations of commodity derivatives,
net |
|
— |
|
|
— |
|
|
(5,409 |
) |
|
— |
|
Premiums paid for commodity derivatives |
|
(1,399 |
) |
|
(5,405 |
) |
|
(9,063 |
) |
|
(20,335 |
) |
Accretion expense |
|
1,041 |
|
|
1,131 |
|
|
4,118 |
|
|
4,472 |
|
(Gain) loss on disposal of assets, net |
|
(67 |
) |
|
1,207 |
|
|
248 |
|
|
5,798 |
|
Write-off of debt issuance costs |
|
935 |
|
|
— |
|
|
935 |
|
|
— |
|
Interest expense |
|
15,044 |
|
|
15,117 |
|
|
61,547 |
|
|
57,904 |
|
Organizational restructuring expenses |
|
— |
|
|
— |
|
|
16,371 |
|
|
— |
|
Litigation settlement |
|
— |
|
|
— |
|
|
(42,500 |
) |
|
— |
|
Income tax (benefit) expense |
|
(1,776 |
) |
|
2,862 |
|
|
(2,588 |
) |
|
4,249 |
|
Adjusted EBITDA |
|
$ |
137,904 |
|
|
$ |
132,370 |
|
|
$ |
560,195 |
|
|
$ |
588,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected Free Cash FlowProjected 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.
Contacts:Ron Hagood: (918) 858-5504 -
RHagood@laredopetro.com
Laredo Petroleum (NYSE:LPI)
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Laredo Petroleum (NYSE:LPI)
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