Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company")
today announced its 2019 first-quarter results, reporting a net
loss attributable to common stockholders of $9.5 million, or $0.04
per diluted share. Adjusted Net Income, a non-GAAP financial
measure, for the first quarter of 2019 was $27.9 million, or $0.12
per diluted share. Adjusted EBITDA, a non-GAAP financial measure,
for the first quarter of 2019 was $122.9 million. Please see
supplemental financial information at the end of this news release
for reconciliations of non-GAAP financial measures.
2019 First-Quarter Highlights
- Produced a Company record 75,276 barrels of oil equivalent
("BOE") per day, driven by continued operational efficiency
improvements that resulted in 20 completions during the quarter,
33% more than originally anticipated
- Reduced combined unit lease operating expenses ("LOE") and unit
cash general and administrative expense ("G&A") to $5.42 per
BOE in the first quarter of 2019, an approximately 11% decrease
from full-year 2018 of $6.07 per BOE, as the Company continued to
focus on controllable cash costs in both field operations and
corporate-level personnel expenses
- Drove down completion costs at the end of the first quarter of
2019, as the Company realized lower prices for in-basin sand and
completion services, reducing per well capital costs by
approximately $500,000 from originally budgeted amounts and
decreasing the Company's per well capital cost to approximately $7
million per well for a 10,000-foot horizontal
- Efficiently managed capital expenditures during first-quarter
2019, resulting in a net debt to Adjusted EBITDA ratio of 1.8
times1, which is expected to hold constant throughout 2019 as
Laredo begins to generate free cash flow in the second quarter of
2019
"The strategy transition that Laredo committed to late last year
is well underway," stated Randy A. Foutch, Chairman and Chief
Executive Officer. "During the first quarter, we completed the two
remaining packages of tightly-spaced wells and are currently
wrapping up completion operations on the first package of wells
developed on wider spacing sooner than expected. We have also
delivered on our pledge to align personnel costs with activity
levels by a recent reduction in force, which cut combined cash,
non-cash and capitalized general and administrative costs by
approximately 25% on an annualized basis. Most importantly, we have
already improved on the plan to operate within cash flow that we
put forth a little over two months ago by restructuring our oil
hedges, securing additional cash flow to increase activity and
substantially accelerating the time frame in which we expect to
generate free cash flow while growing oil production."
"Institutional investors have fundamentally changed how they
measure success for exploration and production companies over the
last few years and we endeavor to listen to all of our
shareholder's input on how we can better operate the Company,"
continued Mr. Foutch. "We have made substantial progress
transitioning Laredo from a net asset value accretion philosophy to
one focused on measured growth with free cash flow generation and
expect to be cash flow neutral for full-year 2019, but recognize
there is more work to do. We look forward to continuing our
communication with all of our investors as we work together to
realize our common goals."
Updated 2019 Operating Plan
Subsequent to the approval of the Company's 2019 capital plan,
Laredo's expected cash flow has benefited from both tactical and
strategic decisions the Company implemented to improve anticipated
financial and operational performance in 2019 and beyond. The
Company restructured its oil hedges in 2019 and 2020 to
significantly raise the weighted-average floor price for both
years, reduced in-basin sand and completion services costs from
those previously budgeted by approximately 25%, settled previously
announced litigation that resulted in a substantial cash payment to
Laredo and delivered on the commitment to cut combined capitalized
and expensed personnel costs. The Company expects to allocate the
combined additional cash flows from these decisions to drilling and
completion activities in 2019 and 2020. The additional activity
improves Laredo's anticipated oil production versus previous
guidance by approximately 3% in 2019 and by approximately 19% in
2020, while maintaining its previously-communicated target of cash
flow neutrality.
The updated operating plan for 2019 increases anticipated well
completions from approximately 36 gross completions to
approximately 52, with the increased activity primarily in the
second half of 2019. The additional activity leverages the benefits
of the previous drilling and completion efficiency improvements
Laredo has demonstrated in the past five years by continuously
operating two drilling rigs and one completion crew through the
second half of 2019.
Laredo now expects to invest approximately $465 million in 2019,
excluding non-budgeted acquisitions, comprised of approximately
$400 million for drilling and completion activities and
approximately $65 million for production facilities, land and other
capitalized costs. Activity and capital expenditures for 2019
continue to be first-half weighted, with approximately 60% of
expected completions and capital expenditures occurring in the
first half of 2019. The Company expects to be cash flow positive
beginning in the second quarter of 2019 and to balance cash flow
and capital expenditures for full-year 2019.
The Company's production profile for 2019 and 2020 should
improve with this additional activity. Total production for
full-year 2019 is now expected to grow approximately 11% versus
full-year 2018 compared to approximately 9% in the original budget.
Oil production for full-year 2019 is expected to decrease
approximately 2% versus full-year 2018 compared to an approximate
5% decrease with the original budget.
The additional completions in the second half of 2019
significantly improve the Company's anticipated production for
full-year 2020 versus the previous budget. Driven by the updated
2019 operating plan, Laredo now expects oil production for
full-year 2020 to be approximately flat versus full-year 2019,
compared to originally guided expectations of a decrease of
approximately 13%. The Company's improved production profile in
2019 and 2020 better positions Laredo for mid-single digit oil
production growth and free cash flow generation in 2021.
E&P Update
During the first quarter of 2019, Laredo continued to
efficiently execute its operational plan, completing 20 gross (19.8
net) horizontal wells with an average completed lateral length of
10,900 feet, exceeding initial expectations of 15 gross horizontal
completions. The 20 wells were completed as two 10-well packages
and were the last of the tight-spacing packages the Company had
previously drilled.
Both oil and total production exceeded guidance in the first
quarter of 2019. Total production averaged a Company record 75,276
BOE per day, an increase of approximately 7% from the previous
quarter and above Company-issued guidance of 74,000 BOE per day.
First-quarter 2019 oil production averaged 28,157 BOPD, an increase
of 1% from the previous quarter and exceeding Company-issued
guidance by more than 2%.
In the second quarter of 2019, Laredo expects to complete 12
gross (11.5 net) horizontal wells with an average completed lateral
length of approximately 11,700 feet. These wells were developed on
the Company's wide-spacing development strategy. The first package
to be completed during the quarter is an eight-well package
co-developing two landing points in the Upper Wolfcamp formation.
The second package is a four-well package developing a single
landing point in the Upper Wolfcamp formation. These wider-spaced
packages are expected to be more productive than the tighter-spaced
packages Laredo focused on in 2017 and 2018 and are expected to
improve the returns and capital efficiency of the Company's
development program.
Laredo continues to take action to drive down capital costs. At
the end of the first quarter of 2019, the Company realized lower
pricing for completion services and in-basin sand than was
budgeted, reducing the per well capital cost for a 10,000-foot
horizontal well by approximately $500,000. The reduction is
expected to be realized for completions through at least the end of
2019.
Additionally, the Company's continued focus on controllable cash
costs reduced combined unit LOE and unit cash G&A to $5.42 per
BOE in the first quarter of 2019 from $6.07 per BOE in full-year
2018. Laredo expects these combined costs to trend down on a unit
basis through 2019 as the Company's reduction in force is expected
to drive unit cash G&A savings and unit LOE is expected to
remain among the lowest in the Midland Basin, driven by benefits
derived from Laredo's field infrastructure investments.
2019 Capital Program
During the first quarter of 2019, Laredo invested approximately
$144 million in drilling and completions activities. Other
expenditures incurred during the quarter included approximately $4
million in bolt-on land acquisitions, lease extensions and data,
approximately $9 million in infrastructure, including Laredo
Midstream Services investments, and approximately $7 million in
other capitalized costs.
Total costs incurred of approximately $164 million in the first
quarter of 2019 was slightly below Laredo's expected capital
expenditures for the quarter, putting the Company on pace to
deliver on the plan to operate within cash flow.
Liquidity
At March 31, 2019, the Company had cash and cash equivalents of
approximately $45 million and available capacity under its senior
secured credit facility of $915 million, resulting in total
liquidity of approximately $960 million.
On April 30, 2019, in connection with the semi-annual
redetermination of the Company's senior secured credit facility,
lenders set the Company's borrowing base at $1.1 billion.
At April 30, 2019, the Company had cash and cash equivalents of
approximately $85 million and available capacity under its senior
secured credit facility of $815 million, resulting in total
available liquidity of approximately $900 million.
Commodity Derivatives
Subsequent to the end of the first quarter of 2019, Laredo
executed a tactical restructuring of its oil hedges for the balance
of 2019 and full-year 2020, and significantly increased hedged
volumes in full-year 2020. This restructuring locked in WTI pricing
approximately 10% higher than the Company's original budgeting and
planning assumptions and approximately 25% higher than the
Company's previous weighted-average floor price over the 21-month
period.
Prior to the restructuring, Laredo's 2019 oil hedges were
predominately puts with a weighted-average floor price of
approximately $47 per barrel. The Company closed substantially all
of its put contracts and in their place entered into swap contracts
at a weighted-average price of $62.02 per barrel for the balance of
2019. This restructuring results in Laredo having approximately 90%
of expected oil production for the balance of 2019 hedged at a
weighted-average floor price of $60.42 per barrel, driving an
anticipated cash flow increase of approximately $60 million as
compared to the Company's initial 2019 budget.
For full-year 2020, the Company closed collars with $45 per
barrel floors and entered into swap contracts at a weighted-average
price of $60.28 per barrel. Laredo now has approximately 75% of
anticipated oil production for full-year 2020 hedged at a
weighted-average floor price of $58.79 per barrel.
Laredo has approximately 70% of its anticipated natural gas
production for the balance of 2019 hedged for both product and
basis. Currently, the Company has natural gas product swaps at a
weighted-average Henry Hub price of $3.09 per MMBtu and WAHA/Henry
Hub basis swaps at a weighted-average price of ($1.51) per MMBtu.
Additionally, Laredo has hedged approximately 65% of anticipated
NGL production for the balance of 2019.
The Company enters into contracts solely with banks that are
part of its senior secured credit facility. Details of the
Company's hedge positions are included in the current Corporate
Presentation available on the Company's website at
www.laredopetro.com.
Guidance
The Company is increasing its anticipated full-year 2019 total
production growth guidance to approximately 11% from a previous
estimate of approximately 9% and improving oil production guidance
to a decrease of approximately 2% from a previous estimate of a 5%
decrease, as compared to full-year 2018. The table below reflects
the Company's guidance for the second quarter of 2019.
|
2Q-2019E |
Total production
(MBOE/d) |
78.5 |
Oil production
(MBO/d) |
28.5 |
|
|
Average sales price
realizations (without derivatives): |
|
Oil (% of
WTI) |
95% |
NGL (% of
WTI) |
20% |
Natural
gas (% of Henry Hub) |
0% |
|
|
Operating costs &
expenses: |
|
Lease
operating expenses ($/BOE) |
$3.30 |
Production and ad valorem taxes (% of oil, NGL and natural gas
revenues) |
6.75% |
Transportation and marketing expenses ($/BOE) |
$0.75 |
Midstream
service expenses ($/BOE) |
$0.15 |
General
and administrative: |
|
Cash
($/BOE) |
$2.00 |
Non-cash
stock-based compensation, net ($/BOE) |
$0.65 |
Depletion, depreciation and amortization ($/BOE) |
$9.30 |
Conference Call Details
On Thursday, May 2, 2019, at 7:30 a.m. CT, Laredo will host a
conference call to discuss its first-quarter 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 8489007, approximately 10
minutes prior to the scheduled conference time. A telephonic replay
will be available approximately two hours after the call on May 2,
2019 through Thursday, May 9, 2010. Participants may access this
replay by dialing 855.859.2056, using conference code 8489007.
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 and midstream and marketing services,
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, estimates or anticipates (and other similar expressions)
will, should or may occur in the future are forward-looking
statements. The forward-looking statements are based on
management’s current belief, based on currently available
information, as to the outcome and timing of future events.
General risks relating to Laredo include, but are not limited
to, the decline in prices of oil, natural gas liquids and natural
gas and the related impact to financial statements as a result of
asset impairments and revisions to reserve estimates, the increase
in service and supply costs, tariffs on steel, pipeline
transportation constraints in the Permian Basin, hedging
activities, possible impacts of pending or potential litigation,
the suspension or discontinuance of share repurchases at any time
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"). 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.
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," 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 added to proved reserves,
largely from a specified resource play. 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 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. Estimates of ultimate recovery 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.
Laredo Petroleum,
Inc.Condensed consolidated statements of
operations
|
|
Three months ended March 31, |
(in thousands, except per share data) |
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Revenues: |
|
|
|
|
Oil, NGL and natural gas
sales |
|
$ |
173,376 |
|
|
$ |
197,434 |
|
Midstream
service revenues |
|
2,883 |
|
|
2,359 |
|
Sales of
purchased oil |
|
32,688 |
|
|
59,903 |
|
Total
revenues |
|
208,947 |
|
|
259,696 |
|
Costs and
expenses: |
|
|
|
|
Lease
operating expenses |
|
22,609 |
|
|
21,951 |
|
Production and ad valorem taxes |
|
7,219 |
|
|
11,812 |
|
Transportation and marketing expenses |
|
4,759 |
|
|
— |
|
Midstream
service expenses |
|
1,603 |
|
|
693 |
|
Costs of
purchased oil |
|
32,691 |
|
|
60,664 |
|
General
and administrative |
|
21,519 |
|
|
24,725 |
|
Depletion, depreciation and amortization |
|
63,098 |
|
|
45,553 |
|
Other
operating expenses |
|
1,052 |
|
|
1,106 |
|
Total
costs and expenses |
|
154,550 |
|
|
166,504 |
|
Operating income |
|
54,397 |
|
|
93,192 |
|
Non-operating income
(expense): |
|
|
|
|
Gain
(loss) on derivatives, net |
|
(48,365 |
) |
|
9,010 |
|
Interest
expense |
|
(15,547 |
) |
|
(13,518 |
) |
Other,
net |
|
(72 |
) |
|
(2,164 |
) |
Non-operating expense, net |
|
(63,984 |
) |
|
(6,672 |
) |
Income
(loss) before income taxes |
|
(9,587 |
) |
|
86,520 |
|
Income tax
benefit: |
|
|
|
|
Deferred |
|
96 |
|
|
— |
|
Total
income tax benefit |
|
96 |
|
|
— |
|
Net income (loss) |
|
$ |
(9,491 |
) |
|
$ |
86,520 |
|
Net income (loss) per
common share: |
|
|
|
|
Basic |
|
$ |
(0.04 |
) |
|
$ |
0.36 |
|
Diluted |
|
$ |
(0.04 |
) |
|
$ |
0.36 |
|
Weighted-average common
shares outstanding: |
|
|
|
|
Basic |
|
230,476 |
|
|
238,228 |
|
Diluted |
|
230,476 |
|
|
239,319 |
|
Laredo Petroleum,
Inc.Condensed consolidated statements of cash
flows
|
|
Three months ended March 31, |
(in thousands) |
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Cash flows from
operating activities: |
|
|
|
|
Net income (loss) |
|
$ |
(9,491 |
) |
|
$ |
86,520 |
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
Deferred
income tax benefit |
|
(96 |
) |
|
— |
|
Depletion, depreciation and amortization |
|
63,098 |
|
|
45,553 |
|
Non-cash
stock-based compensation, net |
|
7,406 |
|
|
9,339 |
|
Mark-to-market on derivatives: |
|
|
|
|
(Gain)
loss on derivatives, net |
|
48,365 |
|
|
(9,010 |
) |
Settlements received (paid) for matured derivatives, net |
|
102 |
|
|
(2,236 |
) |
Premiums
paid for derivatives |
|
(4,016 |
) |
|
(4,024 |
) |
Other,
net |
|
7,776 |
|
|
5,308 |
|
Cash
flows from operating activities before changes in assets and
liabilities |
|
113,144 |
|
|
131,450 |
|
(Increase) decrease in current assets and liabilities, net |
|
(36,750 |
) |
|
15,495 |
|
Decrease
(increase) in other noncurrent assets and liabilities, net |
|
1,064 |
|
|
(474 |
) |
Net cash
provided by operating activities |
|
77,458 |
|
|
146,471 |
|
Cash flows from
investing activities: |
|
|
|
|
Capital
expenditures: |
|
|
|
|
Oil and
natural gas properties |
|
(152,729 |
) |
|
(195,025 |
) |
Midstream
service assets |
|
(2,262 |
) |
|
(3,362 |
) |
Other
fixed assets |
|
(505 |
) |
|
(3,963 |
) |
Proceeds
from disposition of equity method investee, net of selling
costs |
|
— |
|
|
1,655 |
|
Proceeds
from dispositions of capital assets, net of selling costs |
|
43 |
|
|
1,021 |
|
Net cash
used in investing activities |
|
(155,453 |
) |
|
(199,674 |
) |
Cash flows from
financing activities: |
|
|
|
|
Borrowings on Senior Secured Credit Facility |
|
80,000 |
|
|
55,000 |
|
Share
repurchases |
|
— |
|
|
(53,714 |
) |
Stock
exchanged for tax withholding |
|
(2,612 |
) |
|
(4,353 |
) |
Net cash
provided by (used in) financing activities |
|
77,388 |
|
|
(3,067 |
) |
Net decrease in cash
and cash equivalents |
|
(607 |
) |
|
(56,270 |
) |
Cash and cash
equivalents, beginning of period |
|
45,151 |
|
|
112,159 |
|
Cash and cash
equivalents, end of period |
|
$ |
44,544 |
|
|
$ |
55,889 |
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum,
Inc.Selected operating data
|
|
Three months ended March 31, |
|
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Sales volumes: |
|
|
|
|
Oil
(MBbl) |
|
2,534 |
|
|
2,439 |
|
NGL
(MBbl) |
|
2,099 |
|
|
1,563 |
|
Natural
gas (MMcf) |
|
12,849 |
|
|
10,173 |
|
Oil
equivalents (MBOE)(1)(2) |
|
6,775 |
|
|
5,698 |
|
Average
daily sales volumes (BOE/D)(2) |
|
75,276 |
|
|
63,314 |
|
%
Oil(2) |
|
37 |
% |
|
43 |
% |
Average sales
prices(2): |
|
|
|
|
Oil, without
derivatives ($/Bbl)(3) |
|
$ |
50.97 |
|
|
$ |
61.87 |
|
NGL,
without derivatives ($/Bbl)(3) |
|
$ |
15.36 |
|
|
$ |
18.14 |
|
Natural
gas, without derivatives ($/Mcf)(3) |
|
$ |
0.93 |
|
|
$ |
1.79 |
|
Average
price, without derivatives ($/BOE)(3) |
|
$ |
25.59 |
|
|
$ |
34.65 |
|
Oil, with
derivatives ($/Bbl)(4) |
|
$ |
47.66 |
|
|
$ |
58.53 |
|
NGL, with
derivatives ($/Bbl)(4) |
|
$ |
15.33 |
|
|
$ |
18.11 |
|
Natural
gas, with derivatives ($/Mcf)(4) |
|
$ |
1.11 |
|
|
$ |
1.85 |
|
Average
price, with derivatives ($/BOE)(4) |
|
$ |
24.68 |
|
|
$ |
33.34 |
|
Average costs and
expenses per BOE sold(2): |
|
|
|
|
Lease
operating expenses |
|
$ |
3.34 |
|
|
$ |
3.85 |
|
Production and ad valorem taxes |
|
1.07 |
|
|
2.07 |
|
Transportation and marketing expenses |
|
0.70 |
|
|
— |
|
Midstream
service expenses |
|
0.24 |
|
|
0.12 |
|
General
and administrative: |
|
|
|
|
Cash |
|
2.08 |
|
|
2.70 |
|
Non-cash
stock-based compensation, net |
|
1.09 |
|
|
1.64 |
|
Depletion, depreciation and amortization |
|
9.31 |
|
|
7.99 |
|
Total
costs and expenses |
|
$ |
17.83 |
|
|
$ |
18.37 |
|
Cash margins per BOE
sold(2)(5): |
|
|
|
|
Realized |
|
$ |
18.16 |
|
|
$ |
25.91 |
|
Hedged |
|
$ |
17.25 |
|
|
$ |
24.60 |
|
_______________________________________________________________________________
(1) BOE is calculated using a conversion rate of six Mcf per one
Bbl. (2) The numbers presented are based on actual results and
are not calculated using the rounded numbers presented in the table
above. (3) Realized oil, NGL and natural gas prices are the
actual 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 wellhead.
(4) Price reflects the after-effects of our derivative
transactions on our average sales prices. Our calculation of such
after-effects includes settlements of matured derivatives during
the respective periods in accordance with GAAP and an adjustment to
reflect premiums incurred previously or upon settlement that are
attributable to derivatives that settled during the respective
periods. (5) On a per BOE basis, cash margins are
calculated as average 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.Costs incurred
The following table presents costs incurred in the acquisition,
exploration and development of oil and natural gas properties, with
asset retirement obligations included in development costs, for the
periods presented:
|
|
Three months ended March 31, |
(in thousands) |
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Property acquisition
costs: |
|
|
|
|
Evaluated |
|
$ |
— |
|
|
$ |
— |
|
Unevaluated |
|
— |
|
|
— |
|
Exploration
costs |
|
7,505 |
|
|
6,137 |
|
Development
costs |
|
152,717 |
|
|
149,038 |
|
Total
costs incurred |
|
$ |
160,222 |
|
|
$ |
155,175 |
|
|
|
|
|
|
|
|
|
|
Laredo Petroleum,
Inc.Supplemental reconciliations of GAAP to
non-GAAP financial measures
Non-GAAP financial measures
The non-GAAP financial measures of 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 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. 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.
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, 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.
Including a higher weighted-average common shares outstanding in
the denominator of a diluted per share computation results in an
anti-dilutive per share amount when an entity is in a loss
position. As such, our net income (loss) (GAAP) per common share
calculation utilizes the same denominator for both basic and
diluted net income (loss) per common share. However, our
calculation of Adjusted Net Income (non-GAAP) results in income for
both periods presented. Therefore, we believe it appropriate and
more conservative to calculate an adjusted diluted weighted-average
common shares outstanding utilizing our fully dilutive
weighted-average common shares. As such, we present a line item
that calculates Adjusted Net Income per adjusted diluted common
share.
The following table presents a reconciliation of income (loss)
before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
|
|
Three months ended March 31, |
(in thousands, except per share data) |
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Income (loss) before
income taxes |
|
$ |
(9,587 |
) |
|
$ |
86,520 |
|
Plus: |
|
|
|
|
Mark-to-market on derivatives: |
|
|
|
|
(Gain)
loss on derivatives, net |
|
48,365 |
|
|
(9,010 |
) |
Settlements received (paid) for matured derivatives, net |
|
102 |
|
|
(2,236 |
) |
Premiums
paid for derivatives |
|
(4,016 |
) |
|
(4,024 |
) |
Loss on
disposal of assets, net |
|
939 |
|
|
2,617 |
|
Adjusted
income before adjusted income tax expense |
|
35,803 |
|
|
73,867 |
|
Adjusted
income tax expense(1) |
|
(7,877 |
) |
|
(16,251 |
) |
Adjusted
Net Income |
|
$ |
27,926 |
|
|
$ |
57,616 |
|
Net income (loss) per
common share: |
|
|
|
|
Basic |
|
$ |
(0.04 |
) |
|
$ |
0.36 |
|
Diluted |
|
$ |
(0.04 |
) |
|
$ |
0.36 |
|
Adjusted Net Income per
common share: |
|
|
|
|
Basic |
|
$ |
0.12 |
|
|
$ |
0.24 |
|
Adjusted
diluted |
|
$ |
0.12 |
|
|
$ |
0.24 |
|
Weighted-average common
shares outstanding: |
|
|
|
|
Basic |
|
230,476 |
|
|
238,228 |
|
Diluted |
|
230,476 |
|
|
239,319 |
|
Adjusted
diluted |
|
231,531 |
|
|
239,319 |
|
_______________________________________________________________________________
(1) Adjusted income tax expense is calculated by applying a
statutory tax rate of 22% for each of the three months ended
March 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 income taxes, depletion,
depreciation and amortization, non-cash stock-based compensation,
net, accretion expense, mark-to-market on derivatives, premiums
paid for derivatives, interest expense, gains or losses on disposal
of assets 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 those funds
are 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 excluded from the calculation of such term, which 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, the lack of comparability of results
of operations to different companies and 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 March 31, |
(in thousands) |
|
2019 |
|
2018 |
|
|
|
|
|
(unaudited) |
Net income (loss) |
|
$ |
(9,491 |
) |
|
$ |
86,520 |
|
Plus: |
|
|
|
|
Deferred
income tax benefit |
|
(96 |
) |
|
— |
|
Depletion, depreciation and amortization |
|
63,098 |
|
|
45,553 |
|
Non-cash
stock-based compensation, net |
|
7,406 |
|
|
9,339 |
|
Accretion
expense |
|
1,052 |
|
|
1,106 |
|
Mark-to-market on derivatives: |
|
|
|
|
(Gain)
loss on derivatives, net |
|
48,365 |
|
|
(9,010 |
) |
Settlements received (paid) for matured derivatives, net |
|
102 |
|
|
(2,236 |
) |
Premiums
paid for derivatives |
|
(4,016 |
) |
|
(4,024 |
) |
Interest
expense |
|
15,547 |
|
|
13,518 |
|
Loss on
disposal of assets, net |
|
939 |
|
|
2,617 |
|
Adjusted
EBITDA |
|
$ |
122,906 |
|
|
$ |
143,383 |
|
|
|
|
|
|
|
|
|
|
1Net Debt to Adjusted EBITDA
Net debt to Adjusted EBITDA is calculated as net debt as of
March 31, 2019 divided by trailing twelve-month Adjusted EBITDA
ending March 31, 2019 of $568 million. Net debt as of March
31, 2019 was $1.025 billion, calculated as the face value of
debt of $1.070 billion reduced by cash and cash equivalents of $45
million.
Contacts:Ron Hagood: (918) 858-5504 -
RHagood@laredopetro.com
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