C or por a t e Prof i le
Laredo Petroleum is an independent energy company headquartered in
Tulsa, Oklahoma. Laredo’s business strategy is focused on the exploration,
development and acquisition of oil and natural gas properties primarily in
the Permian region of the United States.
A re a s of Ope r a t ion
Our activities are primarily focused on the multi-zone stacked-horizontal
development of our Permian Basin acreage position located in West Texas.
These plays are characterized by high oil and liquids-rich natural gas con-
tent, multiple target horizons, extensive production histories, long-lived
reserves, high drilling success rates and significant resource potential.
PER MI A N BASIN
(WOLFBER RY/WOLFCA MP/CLINE)
■ Oil and liquids-rich natural gas
■
Extensive vertical and horizontal drilling program
L
A
R
E
D
O
P
E
T
R
O
L
E
U
M
|
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0
1
3
A
N
N
U
A
L
R
E
P
O
R
T
Laredo Petroleum, Inc.
15 W. Sixth Street, Suite 900
Tulsa, Oklahoma 74119
Office 918.513.4570
www.laredopetro.com
L A R EDO PETROLEUM | 2013 A NNUA L R EPORT
Laredo is headquartered in Tulsa, OK
with offices in Dallas and Midland, TX
rigcover.indd 1-4
3/20/2014 3:14:43 PM
C or por a t e Prof i le
Laredo Petroleum is an independent energy company headquartered in
Tulsa, Oklahoma. Laredo’s business strategy is focused on the exploration,
development and acquisition of oil and natural gas properties primarily in
the Permian region of the United States.
A re a s of Ope r a t ion
Our activities are primarily focused on the multi-zone stacked-horizontal
development of our Permian Basin acreage position located in West Texas.
These plays are characterized by high oil and liquids-rich natural gas con-
tent, multiple target horizons, extensive production histories, long-lived
reserves, high drilling success rates and significant resource potential.
PER MI A N BASIN
(WOLFBER RY/WOLFCA MP/CLINE)
■ Oil and liquids-rich natural gas
■
Extensive vertical and horizontal drilling program
L
A
R
E
D
O
P
E
T
R
O
L
E
U
M
|
2
0
1
3
A
N
N
U
A
L
R
E
P
O
R
T
Laredo Petroleum, Inc.
15 W. Sixth Street, Suite 900
Tulsa, Oklahoma 74119
Office 918.513.4570
www.laredopetro.com
L A R EDO PETROLEUM | 2013 A NNUA L R EPORT
Laredo is headquartered in Tulsa, OK
with offices in Dallas and Midland, TX
rigcover.indd 1-4
3/20/2014 3:14:43 PM
Dear Stockholders:
In 2013, Laredo continued to execute on the multi-year plan that
we began in 2010 to maximize the value of our Permian Basin
acreage position. Building upon the foundation of the previous
years, we enter 2014 in the enviable position of being completely
focused on our world-class Permian Basin acreage and are begin-
ning to implement an integrated, multi-zone drilling and devel-
opment plan that we believe will significantly enhance the
long-term value of the Company for our stockholders.
More than two years ago we put in place a process to accelerate
the value creation in our Garden City acreage in the Permian
Basin. After confirming the horizontal development reserves in
the Upper Wolfcamp, Middle Wolfcamp, Lower Wolfcamp and
Cline shale zones in 2011 and 2012, we entered 2013 with a
deliberate strategy to optimize an integrated plan for the resource
we have captured. Pursuant to this plan, we divested our
Anadarko Basin assets and redeployed the capital and our per-
sonnel to the Permian Basin.
Reserves and production growth were impressive once again in
2013. Proved reserves increased to a record 203.6 million barrels
of oil equivalent on a two-stream basis, an increase of
R ANDY A. FOUTCH | CHAIR MAN & CHIEF EXECUTIVE OFFICER
approximately 27% when adjusted for the Anadarko Basin dives-
titure. The reserves growth replaced more than 485% of total
production, and more than 575% of Permian production, at a
total finding and development cost of $12.00 per barrel of oil
equivalent. The pre-tax present value of our reserves increased to
$3.1 billion as oil now accounts for 55% of our proved reserves.
Production from our Permian Basin assets increased
Highlights
Corporate Information
Total Proved Reserves
(MMBOE)
Proved Developed Reserves
(MMBOE)
Senior Officers
Randy A. Foutch
Chairman & Chief
Executive Officer
Jay P. Still
President & Chief
Operating Officer
Richard C.
Buterbaugh
Executive Vice
President & Chief
Financial Officer
Patrick J. Curth
Senior Vice
President
Exploration & Land
Kenneth E.
Dornblaser
Senior Vice
President & General
Counsel &
Secretary
Daniel C. Schooley
Senior Vice
President
Midestream &
Marketing
Proved Developed Reserves
Proved Developed Reserves
Independent Directors
Senior Officers
Peter R. Kagan
Warburg Pincus, Managing Director
Randy A. Foutch
Chairman & Chief Executive Officer
approximately 20%, benefiting from the reallocation of resources
develop our acreage. We plan to drill the majority of our hori-
from the divested properties.
Our earlier substantial upfront investment to collect the data
needed to understand the geology and geophysics of the reser-
voirs of our Garden City acreage has accelerated the value recog-
nition from this concentrated block representing approximately
143,000 net acres. We have now confirmed a minimum of four
stacked zones for horizontal development on a significant portion
zontal wells on multi-well pads into the previously identified hor-
izontal zones. By utilizing this process, we anticipate realizing
additional capital and operating cost savings from the efficiencies
gained by reducing the movement of equipment and the concen-
tration of facilities in our production corridors. We believe this
integrated approach will be the optimal way to maximize the
value of the prize we have captured.
of our acreage which represents the effective equivalent of at least
We wish to recognize the employees of Laredo for their efforts
360,000 net acres of single-zone resource plays. The resource
and contributions to our success in 2013. During the year we
potential of just this confirmed acreage and zones is estimated at
increased our employee count by more than 40% while main-
more than 1.6 billion barrels of oil equivalent.
taining our commitment to the Laredo culture of integrity, stew-
Our integrated development plan has been designed to efficiently
recover these resources. It also provides the flexibility to incor-
porate additional acreage and zones into our overall plan to max-
imize the value from this acreage position. Although our
near-term focus is on accelerating the development program, we
continue to evaluate the remaining acreage and other prospective
zones that underlay our acreage that are not yet de-risked.
Our successes in 2013 are the building blocks for our plans in
2014. We have incorporated what we have learned into our inte-
grated development plan. We have begun to implement a system
of production corridors that will support the drilling and produc-
tion operations for thousands of horizontal wells to efficiently
ardship, respect, teamwork and success which is integral to our
progress. I also thank our Board of Directors, whose members
provide invaluable guidance and counsel. Mostly, we appreciate
the support of our stockholders, who trust us to guide their
company.
Randy A. Foutch
Chairman & Chief Executive Officer
Jay P. Still
Director, President &
Chief Operating Officer
Richard C. Buterbaugh
Executive Vice President &
Chief Financial Officer
Patrick J. Curth
Senior Vice President,
Exploration & Land
Kenneth E. Dornblaser
Senior Vice President &
General Counsel & Secretary
Daniel C. Schooley
Senior Vice President
Midstream & Marketing
James R. Levy
Warburg Pincus, Managing Director
B.Z. (Bill) Parker
Phillips Petroleum Company,
Former Executive Vice President
Pamela S. Pierce
Ztown Investments, Inc., Partner
Ambassador Francis Rooney
Rooney Holdings, Inc. &
Manhattan Construction Group, Chief
Executive Officer
Dr. Myles W. Scoggins
Colorado School of Mines, President
Edmund P. Segner, III
EOG Resources, Former President,
Chief of Staff & Director
Donald D. Wolf
Quantum Resources Management,
LLC, Chairman
Directors
Randy A. Foutch
Chairman & Chief Executive Officer
Jay P. Still
Director, President &
Chief Operating Officer
Stock Transfer Agent
American Stock Transfer and
Trust Company
6201 15th Avenue
Brooklyn, NY 11219
(800) 937-5449
Independent Auditors
Grant Thornton LLP
2431 East 61st Street, Suite 500
Tulsa, OK 74136
(918) 877-0800
Third-Party Reserve Engineers
Ryder Scott Company, L.P.
Petroleum Consultants
TBPE Registered Engineering
Firm F-1580
1100 Louisiana, Suite 3800
Houston, TX 77002
(713) 651-9191
Legal Counsel
Akin Gump Strauss Hauer & Feld LLP
1111 Louisiana Street, 44th Floor
Houston, TX 77002
(713) 220-5800
Stock Exchange Listing
Laredo’s common shares are
publicly traded on the NYSE
under the symbol “LPI.”
rigcover.indd 5-8
3/20/2014 3:14:46 PM
Dear Stockholders:
In 2013, Laredo continued to execute on the multi-year plan that
we began in 2010 to maximize the value of our Permian Basin
acreage position. Building upon the foundation of the previous
years, we enter 2014 in the enviable position of being completely
focused on our world-class Permian Basin acreage and are begin-
ning to implement an integrated, multi-zone drilling and devel-
opment plan that we believe will significantly enhance the
long-term value of the Company for our stockholders.
More than two years ago we put in place a process to accelerate
the value creation in our Garden City acreage in the Permian
Basin. After confirming the horizontal development reserves in
the Upper Wolfcamp, Middle Wolfcamp, Lower Wolfcamp and
Cline shale zones in 2011 and 2012, we entered 2013 with a
deliberate strategy to optimize an integrated plan for the resource
we have captured. Pursuant to this plan, we divested our
Anadarko Basin assets and redeployed the capital and our per-
sonnel to the Permian Basin.
Reserves and production growth were impressive once again in
2013. Proved reserves increased to a record 203.6 million barrels
of oil equivalent on a two-stream basis, an increase of
R ANDY A. FOUTCH | CHAIR MAN & CHIEF EXECUTIVE OFFICER
approximately 27% when adjusted for the Anadarko Basin dives-
titure. The reserves growth replaced more than 485% of total
production, and more than 575% of Permian production, at a
total finding and development cost of $12.00 per barrel of oil
equivalent. The pre-tax present value of our reserves increased to
$3.1 billion as oil now accounts for 55% of our proved reserves.
Production from our Permian Basin assets increased
Highlights
Corporate Information
Total Proved Reserves
(MMBOE)
Proved Developed Reserves
(MMBOE)
Senior Officers
Randy A. Foutch
Chairman & Chief
Executive Officer
Jay P. Still
President & Chief
Operating Officer
Richard C.
Buterbaugh
Executive Vice
President & Chief
Financial Officer
Patrick J. Curth
Senior Vice
President
Exploration & Land
Kenneth E.
Dornblaser
Senior Vice
President & General
Counsel &
Secretary
Daniel C. Schooley
Senior Vice
President
Midestream &
Marketing
Proved Developed Reserves
Proved Developed Reserves
approximately 20%, benefiting from the reallocation of resources
develop our acreage. We plan to drill the majority of our hori-
from the divested properties.
Our earlier substantial upfront investment to collect the data
needed to understand the geology and geophysics of the reser-
voirs of our Garden City acreage has accelerated the value recog-
nition from this concentrated block representing approximately
143,000 net acres. We have now confirmed a minimum of four
stacked zones for horizontal development on a significant portion
zontal wells on multi-well pads into the previously identified hor-
izontal zones. By utilizing this process, we anticipate realizing
additional capital and operating cost savings from the efficiencies
gained by reducing the movement of equipment and the concen-
tration of facilities in our production corridors. We believe this
integrated approach will be the optimal way to maximize the
value of the prize we have captured.
of our acreage which represents the effective equivalent of at least
We wish to recognize the employees of Laredo for their efforts
360,000 net acres of single-zone resource plays. The resource
and contributions to our success in 2013. During the year we
potential of just this confirmed acreage and zones is estimated at
increased our employee count by more than 40% while main-
more than 1.6 billion barrels of oil equivalent.
taining our commitment to the Laredo culture of integrity, stew-
Our integrated development plan has been designed to efficiently
recover these resources. It also provides the flexibility to incor-
porate additional acreage and zones into our overall plan to max-
imize the value from this acreage position. Although our
near-term focus is on accelerating the development program, we
continue to evaluate the remaining acreage and other prospective
zones that underlay our acreage that are not yet de-risked.
Our successes in 2013 are the building blocks for our plans in
2014. We have incorporated what we have learned into our inte-
grated development plan. We have begun to implement a system
of production corridors that will support the drilling and produc-
tion operations for thousands of horizontal wells to efficiently
ardship, respect, teamwork and success which is integral to our
progress. I also thank our Board of Directors, whose members
provide invaluable guidance and counsel. Mostly, we appreciate
the support of our stockholders, who trust us to guide their
company.
Randy A. Foutch
Chairman & Chief Executive Officer
publicly traded on the NYSE
under the symbol “LPI.”
rigcover.indd 5-8
3/20/2014 3:14:46 PM
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-35380
Laredo Petroleum, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
15 W. Sixth Street, Suite 1800
Tulsa, Oklahoma
(Address of principal executive offices)
45-3007926
(I.R.S. Employer
Identification No.)
74119
(Zip code)
(918) 513-4570
(Registrant's telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange On Which Registered
Common Stock, $0.01 par value per share
New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the
preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a
smaller reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
Aggregate market value of the voting and non-voting common equity held by non-affiliates was approximately $870.1 million on
June 28, 2013, based on $20.56 per share, the last reported sales price of the common stock on the New York Stock Exchange on such date.
Number of shares of registrant's common stock outstanding as of February 24, 2014: 142,618,804
Documents Incorporated by Reference:
Portions of the registrant's definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference into Part III of this report for the
year ended December 31, 2013.
Laredo Petroleum, Inc.
Table of Contents
Glossary of Oil and Natural Gas Terms.................................................................................................
Cautionary Statement Regarding Forward-Looking Statements ...........................................................
Item 1.
Part I
Business .................................................................................................................................................
Item 1A.
Risk Factors ...........................................................................................................................................
Item 1B.
Unresolved Staff Comments ..................................................................................................................
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Properties ...............................................................................................................................................
Legal Proceedings..................................................................................................................................
Mine Safety Disclosures ........................................................................................................................
Part II
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities ....................................................................................................................................
Selected Historical Financial Data.........................................................................................................
Management's Discussion and Analysis of Financial Condition and Results of Operations.................
Item 7A.
Quantitative and Qualitative Disclosure About Market Risk ................................................................
Item 8.
Item 9.
Financial Statements and Supplementary Data......................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................
Item 9A.
Controls and Procedures ........................................................................................................................
Item 9B.
Other Information ..................................................................................................................................
Item 10.
Part III
Directors, Executive Officers and Corporate Governance.....................................................................
Item 11.
Executive Compensation .......................................................................................................................
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters ...................................................................................................................................................
Item 13.
Certain Relationships and Related Transactions, and Director Independence ......................................
Item 14.
Principal Accounting Fees and Services................................................................................................
Item 15.
Part IV
Exhibits, Financial Statement Schedules ...............................................................................................
3
5
6
29
45
45
45
45
46
48
51
73
75
75
75
78
79
79
79
79
79
80
2
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following terms are used throughout this Annual Report on Form 10-K (this "Annual Report"):
"2D"—Method for collecting, processing and interpreting seismic data in two dimensions.
"3D"—Method for collecting, processing and interpreting seismic data in three dimensions.
"Basin"—A large natural depression on the earth's surface in which sediments generally brought by water accumulate.
"Bbl"—One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or
natural gas liquids.
"BOE"—One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of
natural gas to one Bbl of oil.
"BOE/D"—BOE per day.
"Btu"—British thermal unit, the quantity of heat required to raise the temperature of a one pound mass of water by one
degree Fahrenheit.
"Completion"—The process of treating a drilled well followed by the installation of permanent equipment for the
production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
"Developed acreage"—The number of acres that are allocated or assignable to productive wells or wells capable of
production.
"Development well"—A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
"Dry hole"—A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the
sale of such production exceed production expenses and taxes.
"Exploratory well"—A well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.
"Facies"—A lateral change in a stratigraphic rock unit due to variance in the formation's petrophysical attribute(s).
"Field"—An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual
geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both
the surface and the underground productive formations.
"Formation"—A layer of rock which has distinct characteristics that differs from nearby rock.
"Fracturing ("Frac")"—The propagation of fractures in a rock layer by a pressurized fluid. This technique is used to
release petroleum and natural gas for extraction.
"Gross acres" or "gross wells"—The total acres or wells, as the case may be, in which a working interest is owned.
"Horizon"—A term used to denote a surface in or of rock, or a distinctive layer of rock that might be represented by a
reflection in seismic data.
"Horizontal drilling"—A drilling technique used in certain formations where a well is drilled vertically to a certain depth
and then drilled at a right angle within a specified interval.
"Initial Production"—The measurement of production from an oil or gas well when first brought on stream. Often stated
in terms of production during the first thirty days.
"Liquids"—Describes oil, condensate and natural gas liquids.
"MBbl"—One thousand barrels of crude oil, condensate or natural gas liquids.
"MBOE"—One thousand BOE.
"Mcf"—One thousand cubic feet of natural gas.
"MMBtu"—One million British thermal units.
3
"MMcf"—One million cubic feet of natural gas.
"Natural gas liquid"—Components of natural gas that are separated from the gas state in the form of liquids, which
include propane, butanes and ethane, among others.
"Net acres"—The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An
owner who has 50% interest in 100 acres owns 50 net acres.
"NYMEX"—The New York Mercantile Exchange.
"Productive well"—A well that is found to be capable of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of the production exceed production expenses and taxes.
"Proved developed non-producing reserves ("PDNP")"—Developed non-producing reserves.
"Proved developed reserves ("PDP")"—Reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods.
"Proved reserves"—The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under
existing economic and operating conditions.
"Proved undeveloped reserves ("PUD")"—Proved reserves that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively major expenditure is required for recompletion.
"Recompletion"—The process of re-entering an existing wellbore that is either producing or not producing and
completing new reservoirs in an attempt to establish or increase existing production.
"Reservoir"—A porous and permeable underground formation containing a natural accumulation of producible oil and/or
natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
"Resource play" —An expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that
has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and
multi-stage fracturing technologies.
"Spacing"—The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres,
e.g., 40-acre spacing, and is often established by regulatory agencies.
"Standardized measure"—Discounted future net cash flows estimated by applying year-end prices to the estimated future
production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs
based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the
statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash
inflows after income taxes are discounted using a 10% annual discount rate.
"Two stream"—Production or reserve volumes of oil and wet natural gas, where the natural gas liquids have not been
removed from the natural gas stream and the economic value of the natural gas liquids is included in the wellhead natural gas
price.
"Undeveloped acreage"—Lease acreage on which wells have not been drilled or completed to a point that would permit
the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
"Wellhead natural gas"—Natural gas produced at or near the well.
"Working interest" or "WI"—The right granted to the lessee of a property to explore for and to produce and own natural
gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash,
penalty or carried basis.
4
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this Annual Report are forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements include statements,
projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling
program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects
of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally
accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may,"
"will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other
variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not
guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our
experience and our perception of historical trends, current conditions and expected future developments as well as other factors
we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact
our business in the future are:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the recent instability and uncertainty in the U.S. and international financial and consumer markets that is adversely
affecting the liquidity available to us and our customers and is adversely affecting the demand for commodities,
including oil and natural gas;
the volatility of oil and natural gas prices;
the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and
natural gas wells;
the possible introduction of regulations that prohibit or restrict our ability to drill new allocation wells;
discovery, estimation, development and replacement of oil and natural gas reserves, including our expectations that
estimates of our proved reserves will increase;
uncertainties about the estimates of our oil and natural gas reserves;
competition in the oil and natural gas industry;
the availability and costs of drilling and production equipment, labor and oil and natural gas processing and other
services;
drilling and operating risks, including risks related to hydraulic fracturing activities;
risks related to the geographic concentration of our assets;
changes in domestic and global demand for oil and natural gas, as well as the continuation of restrictions on the export
of domestic crude oil;
the availability of sufficient pipeline and transportation facilities and gathering and processing capacity;
changes in the regulatory environment and changes in international, legal, political, administrative or economic
conditions;
our ability to comply with federal, state and local regulatory requirements;
our ability to execute our strategies, including but not limited to our hedging strategies;
our ability to recruit and retain the qualified personnel necessary to operate our business;
evolving industry standards and adverse changes in global economic, political and other conditions;
restrictions contained in our debt agreements, including our senior secured credit facility and the indentures governing
our senior unsecured notes, as well as debt that could be incurred in the future;
our ability to access additional borrowing capacity under our senior secured credit facility or other means of providing
liquidity; and
our ability to generate sufficient cash to service our indebtedness and to generate future profits.
These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ
materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be
considered in light of various factors, including those set forth in this Annual Report under "Item 1A. Risk Factors," in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Annual Report.
In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These
forward-looking statements speak only as of the date of this Annual Report, or if earlier, as of the date they were made. We do
not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.
5
Part I
On December 31, 2013, Laredo Petroleum Holdings, Inc., a Delaware corporation, completed an internal corporate
reorganization and changed its name to Laredo Petroleum, Inc. See "Item 1. Business — Corporate history and structure" for
more information. Unless the context otherwise requires, references in this Annual Report to “Laredo,” the “Company,”
“we,” “our,” “us,” or similar terms refer to Laredo Petroleum Holdings, Inc. and its subsidiaries, including Laredo
Petroleum, Inc., a Delaware corporation, before the completion of our internal corporate reorganization and to Laredo
Petroleum, Inc. and its subsidiary, Laredo Midstream Services, LLC, as of the completion of our internal corporate
reorganization and thereafter.
In this Annual Report, the consolidated and historical financial information, operational data and reserve information
for Laredo and our acquired subsidiary Broad Oak Energy, Inc. ("Broad Oak"), a Delaware corporation, present the assets and
liabilities of Laredo and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were
consolidated for all periods presented prior to July 1, 2011. Although the financial and other information is reported on a
consolidated basis, such presentation is not necessarily indicative of the results that would have been obtained if Laredo had
owned and operated Broad Oak from its inception. See Notes A and B in our audited consolidated financial statements included
elsewhere in this Annual Report for more information.
All amounts, dollars and percentages presented in this Annual Report are rounded and therefore approximate.
Item 1. Business
Overview
Laredo is an independent energy company focused on the exploration, development and acquisition of oil and natural
gas properties primarily in the Permian region of the United States. The oil and liquids-rich Permian Basin in West Texas is
characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and
high initial production rates. As of December 31, 2013, we had assembled 202,084 net acres in the Permian Basin and had total
proved reserves, presented on a two-stream basis, of 203,615 MBOE.
On August 1, 2013, we completed the sale of our assets in the Anadarko Basin in the Texas Panhandle and Western
Oklahoma (the “Anadarko Basin Sale”) which represented 15% of our proved reserve volumes as of December 31, 2012.
Following the Anadarko Basin Sale, the percentage of our proved reserves attributable to oil increased to 55% as of December
31, 2013 from 52% prior to such sale.
Our primary exploration and production fairway in the Permian Basin is centered on the eastern side of the basin
35 miles east of Midland, Texas and extends 20 miles wide (east/west) and 85 miles long (north/south) in Glasscock, Howard,
Reagan, Sterling and Tom Green counties, and is referred to in this Annual Report as the "Permian-Garden City" area. As of
December 31, 2013, we held 143,212 net acres in more than 300 sections in the Permian-Garden City area, with an average
working interest of 96% in all Laredo-operated producing wells.
We believe our acreage in the Permian-Garden City area is a resource play for the Wolfberry interval, comprised of
multiple producing formations, including the initial four identified shale zones targeted for horizontal drilling (Upper, Middle
and Lower Wolfcamp and Cline shales). From our inception through December 31, 2013, we have drilled and completed 96
horizontal wells in these four target zones, and 818 vertical wells in the Wolfberry interval. We have completed (i.e., the
particular well is flowing) 40 horizontal Upper Wolfcamp wells, 13 horizontal Middle Wolfcamp wells, six horizontal Lower
Wolfcamp wells and 37 horizontal Cline wells. Our horizontal activity since mid-2012 has moved toward drilling longer
laterals (typically 7,000 to 7,500 feet) and increased frac density (typically 25 to 28 stages) as we continue the optimization of
our completion techniques.
6
As illustrated in the following table, as a result of our drilling activity through 2013 coupled with our technical data
and well performance, we believe that as of December 31, 2013 we have confirmed the horizontal development potential for
the equivalent of 360,000 net acres from the four zones, as well as our entire Permian-Garden City acreage position for vertical
development.
Upper Wolfcamp................................................................................................................................
Middle Wolfcamp..............................................................................................................................
Lower Wolfcamp...............................................................................................................................
Cline ..................................................................................................................................................
Total.................................................................................................................................................
Horizontal development
de-risked net acreage as of
December 31, 2013
80,000
80,000
73,000
127,000
360,000
Going forward, we plan to continue drilling and collecting technical data across our Permian-Garden City acreage, as
reflected in our 2014 capital drilling budget allocation. As a result, we expect our Permian-Garden City acreage to be the
primary driver of our reserves, production and cash flow growth for the foreseeable future.
Laredo was founded in October 2006 by our Chairman and Chief Executive Officer Randy A. Foutch, who was later
joined by other members of our management team. Prior to founding Laredo, Mr. Foutch formed, built and sold three private
oil and natural gas companies. All of these companies executed the same fundamental business strategy employed by Laredo
and created significant economic value through growth in reserves, production and cash flow.
In December 2011, we completed a Corporate Reorganization and IPO and in December 2013, we completed a
separate internal corporate reorganization. See "—Corporate history and structure."
Since our inception, we have rapidly grown our reserves, production and cash flow through both our drilling program
and strategic acquisitions, including our July 2011 acquisition of Broad Oak. Our net proved reserves were estimated at
203,615 MBOE as of December 31, 2013, of which 35% are classified as proved developed reserves and 55% are attributed to
oil reserves. Our reserves and production are reported in two streams: crude oil and liquids-rich natural gas. The economic
value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. In this Annual Report, the
information presented with respect to our estimated proved reserves has been prepared by Ryder Scott Company, L.P. ("Ryder
Scott"), our independent reserve engineers, in accordance with the rules and regulations of the Securities and Exchange
Commission ("SEC") applicable to the periods presented.
7
The following table summarizes our total estimated net proved reserves presented on a two-stream basis, net acreage
and producing wells as of December 31, 2013, and average daily production presented on a two-stream basis for the year ended
December 31, 2013. Based on estimates in the report prepared by Ryder Scott, we operate wells that represent 98% of the
economic value of our proved developed oil and natural gas reserves as of December 31, 2013.
Permian ...........................................
Anadarko Granite Wash(4)...............
Other Areas(5) ..................................
New Ventures(6)...............................
Total..............................................
MBOE
203,564
—
—
51
As of December 31, 2013
Estimated net
proved reserves(1)(2)
Producing
wells
% of
total reserves
% Oil
Net
acreage
Gross
Net
55% 202,084
1,060
940
99%
—%
—%
—%
—%
—
—
1% 100%
80,143
—
—
1
—
—
1
203,615
100%
55% 282,227
1,061
941
Year ended
December 31, 2013
average daily
production(3)
(BOE/D)
24,897
4,615
1,141
63
30,716
_____________________________________________________________________________
(1) Our estimated net proved reserves were prepared by Ryder Scott, presented on a two-stream basis as of December 31,
2013 and are based on reference oil and natural gas prices. In accordance with applicable rules of the SEC, the
reference oil and natural gas prices are derived from the average trailing 12-month index prices (calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable 12-month
period), held constant throughout the life of the properties. The reference prices were $93.52 per Bbl for oil and $3.57
per MMBtu for natural gas for the 12 months ended December 31, 2013.
(2) Because our reserves are reported in two streams, the economic value of the natural gas liquids in our natural gas is
included in the wellhead natural gas price. The reference prices referred to above that were utilized in the
December 31, 2013 reserve report prepared by Ryder Scott are adjusted for natural gas liquids content, quality,
transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price
received at the wellhead. The adjusted reference price was $5.52 per Mcf.
(3) Our average daily production volumes are reported in two streams: crude oil and liquids-rich natural gas. The
economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.
(4) We sold these assets on August 1, 2013.
(5) We sold these assets on August 1, 2013, which included our acreage in the gas prone Eastern Anadarko (21,000 net
acres) and Central Texas Panhandle (43,450 net acres).
(6) On December 20, 2013, we completed the sale of certain properties in the Dalhart Basin, which included 37,000 net
acres. The remaining 50,000 net acres that we own in the Dalhart Basin are included in New Ventures. See "—New
Ventures."
Our net average daily production for the year ended December 31, 2013 was 30,716 BOE/D, 49% of which was oil
and 51% of which was primarily liquids-rich natural gas. Our drilling activity has been and is expected to continue to be
focused on oil opportunities in the Permian Basin.
Following the sale of our assets in the Anadarko Basin and Dalhart Basin, we continue to focus on horizontal drilling
in the Permian Basin. This Permian Basin horizontal drilling program comprises an extensive, multi-year, multiple-zone
inventory of exploratory and development opportunities.
As of December 31, 2013 we had completed 96 gross horizontal Wolfcamp and Cline shale wells in our Permian-
Garden City area.
Substantially all of our $1 billion planned capital budget for 2014 is anticipated to be invested in the Permian Basin.
We anticipate that we will continue to drill vertical wells for purposes of further delineating our Permian Basin acreage and
holding all prospective targeted zones. We are increasingly allocating a greater percentage of both capital and human resources
towards our horizontal drilling activity, which generally produces even more attractive economics than our vertical program.
Because of the stacked multiple-zone horizontal targets underlying our acreage, we are continuing to refine the optimal
geometry relative to well spacing, both vertically and horizontally, lateral placement, completion and production practices.
Work to date has included the pad drilling of side-by-side wells within the same zone, stacked lateral wells and extensive
reservoir modeling.
8
On December 31, 2013 we had a total of 11 operated drilling rigs working on our properties in the Permian-Garden
City area, consisting of six rigs drilling vertical wells and five rigs drilling horizontal wells.
We have assembled a multi-year inventory of development drilling and exploitation projects as a result of our early
acquisition of technical data, early establishment of significant concentrated acreage positions and successful exploratory
drilling.
While our horizontal drilling programs will be focused primarily on developing the four zones already identified in the
liquids-rich Wolfcamp and Cline intervals underlying our Permian-Garden City properties, we believe, based on petrophysical
analysis, additional potential may exist in both shallower and deeper formations. The testing of these new targeted intervals will
be integrated into our drilling program during 2014 and beyond.
We maintain a financial profile that provides operational flexibility. At December 31, 2013, we had $825 million
available for borrowings under our Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit
Facility") and total debt of $1.05 billion, of which no amount was outstanding under our Senior Secured Credit Facility. Our
total debt, less available cash on the balance sheet, was 1.8 times our Adjusted EBITDA (a non-GAAP financial measure, see
"Item 6. Selected Historical Financial Data—Non-GAAP financial measures and reconciliations") for the year ended December
31, 2013. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the capability to
implement our planned exploration and development activities as well as the ability to accelerate our capital program, if
deemed appropriate. We use derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a
significant portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the
potential effects of variability in cash flows from operations due to fluctuations in commodity prices.
We carefully assess and monitor many factors in our drilling and exploration projects. Our drilling activities in areas
containing extensive historical industry activity have enabled us to determine whether a prospective reservoir underlies our
acreage position, and whether it can be defined both vertically and horizontally. We use a number of proven mapping
techniques to understand the physical extent of the targeted reservoir. This includes 2D and 3D seismic data, as well as Laredo-
owned and historical public well databases (which in the Permian Basin may extend back more than 80 years). We also utilize
our laboratory and field derived data from whole cores, sidewall cores, well cuttings, mudlogs and open-hole well logs to
understand the petrophysics of the rock characteristics prior to the commencement of any completion operations. Finally, after
defining the reservoir, our engineers utilize their technical expertise to develop completion programs that we believe will
maximize the amount of hydrocarbons that can be economically recovered. As more wells are completed in the targeted
reservoir and additional data becomes available, the process is further refined. Based on these and other factors, we consider
our acreage to be "de-risked" (i.e., having reduced the risk and uncertainty associated therewith) when we believe we have
established the ability to commercially produce from a certain area.
In the Permian-Garden City area, the Wolfberry interval, comprised of multiple producing formations, including the
Wolfcamp and Cline shale formations targeted for horizontal drilling in four zones (Upper, Middle and Lower Wolfcamp and
Cline shales), is considered a resource play. While the vertical component of the drilling program will continue, our emphasis is
now centered on bringing forward the upside potential in the Wolfcamp and Cline shales in our Permian-Garden City acreage
through horizontal drilling. As resource plays, the mapping of the gross interval for each of the producing formations
underlying a majority of our acreage position is the primary factor in identifying our potential drilling locations. In the general
region and immediately around our acreage position, publicly available well data exists from a significant number of vertical
wells (in excess of several thousand for the Wolfcamp and Cline shales alone) that allows us to better define the potential areal
extent of each of the producing intervals. In addition to the publicly available well data, we have also incorporated our
internally generated information from cores, 3D seismic, open-hole logging, production and reservoir engineering data into
defining the extent of the targeted formations, the ability of such formations to produce commercial quantities of hydrocarbons,
and the viability of the potential locations. We are refining a development plan for a portion of our Permian-Garden City area in
order to minimize costs and maximize recoveries and began its implementation in 2013. As of December 31, 2013, we had
drilled and completed 10 horizontal wells as a part of our pad drilling program.
The timing of drilling our potential locations is influenced by several factors, including commodity prices, capital
requirements, the Texas Railroad Commission ("RRC") well-spacing requirements and the continuation of the positive results
from our ongoing development drilling program.
Corporate history and structure
Laredo Petroleum Holdings, Inc. was incorporated in August 2011 pursuant to the laws of the State of Delaware for
purposes of a corporate reorganization and initial public offering ("IPO"). The corporate reorganization, pursuant to which
Laredo Petroleum, LLC was merged with and into Laredo Petroleum Holdings, Inc., with Laredo Petroleum Holdings, Inc.
9
surviving the merger, was completed on December 19, 2011 (the "Corporate Reorganization"). Laredo Petroleum, LLC was
formed in 2007 pursuant to the laws of the State of Delaware by affiliates of Warburg Pincus LLC ("Warburg Pincus"), our
institutional investor, and the management of Laredo Petroleum, Inc., which was founded in 2006 by Randy A. Foutch, our
Chairman and Chief Executive Officer, to acquire, develop and operate oil and natural gas properties in the Permian and Mid-
Continent regions of the United States. In the Corporate Reorganization, all of the outstanding preferred equity interests and
certain of the incentive equity interests in Laredo Petroleum, LLC were exchanged for shares of common stock of Laredo
Petroleum Holdings, Inc. Laredo Petroleum Holdings, Inc. completed an IPO of its common stock on December 20, 2011. As
of December 31, 2013, Warburg Pincus owned 49.1% of our common stock.
On July 1, 2011, we completed the acquisition of Broad Oak, which became a wholly-owned subsidiary of Laredo
Petroleum, Inc. Broad Oak was formed in 2006 with financial support from its management and Warburg Pincus. On July 19,
2011, we changed the name of Broad Oak to Laredo Petroleum—Dallas, Inc.
Effective December 31, 2013, we completed an internal corporate reorganization, which simplified our corporate
structure. Our two former subsidiaries Laredo Petroleum Texas, LLC and Laredo Petroleum—Dallas, Inc. were merged with
and into Laredo Petroleum, Inc. The sole remaining wholly-owned subsidiary of Laredo Petroleum, Inc., formerly known as
Laredo Gas Services, LLC, changed its name to Laredo Midstream Services, LLC. Laredo Petroleum, Inc., a wholly-owned
subsidiary of Laredo Petroleum Holdings, Inc. ("Holdings"), merged with and into Holdings with Holdings surviving and
changing its name to “Laredo Petroleum, Inc.” We refer to the events described in this paragraph collectively as the "Internal
Consolidation." The Corporate Reorganization, IPO and Internal Consolidation are discussed in Note A to our audited
consolidated financial statements included elsewhere in this Annual Report.
Laredo Petroleum, Inc. is the borrower under our Senior Secured Credit Facility, as well as the issuer of our $550
million 9 1/2% senior unsecured notes due 2019 (the "2019 senior unsecured notes") issued in January and October 2011, our
$500 million 7 3/8% senior unsecured notes due 2022 issued in April 2012 (the "2022 senior unsecured notes") and our $450
million 5 5/8% senior unsecured notes due 2022 issued in January 2014 (the "new senior unsecured notes"). We refer to the
2019 senior unsecured notes, the 2022 senior unsecured notes and the new senior unsecured notes collectively as the "senior
unsecured notes." Our subsidiary, Laredo Midstream Services, LLC ("Laredo Midstream"), is a guarantor of the obligations
under our Senior Secured Credit Facility and senior unsecured notes.
Our business strategy
Our goal is to enhance stockholder value by economically growing our reserves, production and cash flow by
executing the following strategy:
Grow reserves, production and cash flow. As of December 31, 2013, we had 143,212 net acres in the Permian-
Garden City area. As of such date we believe we have established the economic horizontal potential of 80,000 net acres for
horizontal Upper Wolfcamp drilling, 80,000 net acres for horizontal Middle Wolfcamp drilling, 73,000 net acres for Lower
Wolfcamp drilling and 127,000 net acres for horizontal Cline drilling. We are continuing to de-risk the remaining acreage for
these zones, although at a slower pace than in the past. We believe the opportunities afforded in our Permian-Garden City area
will support consistent, predictable, annual growth in reserves, production and cash flow.
Initiating a development plan for our Permian-Garden City acreage. We believe our Permian-Garden City acreage
will be the primary driver of our reserves, production and cash flow growth for the foreseeable future. Based on additional
drilling results through December 31, 2013, coupled with our technical data and well performance, we believe we have
confirmed the vertical development potential of our entire Permian-Garden City acreage position (utilizing more than 800
vertical wells across our acreage position, of which more than 300 have been drilled through the Wolfcamp, Cline and Atoka
formations). The equivalent of 360,000 net acres for commercial horizontal development has been proven from all four targeted
zones based on 96 horizontal wells drilled and completed as of December 31, 2013. We further believe this de-risked acreage
position provides a multi-year development inventory to support consistent growth of reserves, production and cash flow. We
are implementing a systematic pad development drilling program that will allow us to optimize spacing, minimize drainage
interference and maximize our frac design. Because of the complexities of developing a field that has multi-dimensional
aspects (vertical and horizontal reservoir components), we have drilled and tested side-by-side horizontal wells (same
reservoir) with the initial results supporting 660-ft. spacing at or above our internal production estimates. The stacked lateral
program (up to four different zones) has been initiated with multiple tests planned in several areas of our acreage in 2014. Our
objectives with the stacked lateral program are to optimize the vertical distance between the laterals, minimize interference,
enhance frac design and maximize scheduling of rig operations on multi-well pads. The plan also calls for having the flexibility
to include the de-risking of additional acreage for both the Wolfcamp and the Cline shale intervals while furthering the
development of the Middle and Lower Wolfcamp zones in the southern half of the Permian-Garden City acreage. The drilling
and testing of other potential zones (i.e., Spraberry and ABW) will likely also be part of the 2014 drilling program. Going
10
forward, we plan to continue drilling and collecting technical data across our Permian-Garden City acreage position.
Capitalize on technical expertise and database. We are leveraging our operating and technical expertise to further
delineate and develop our core acreage positions. We believe that we have de-risked a significant portion of our Permian-
Garden City acreage through the utilization of an extensive technical petrophysical database, a vertical drilling program
covering a majority of our core acreage position, numerous vertical single-zone tests in our horizontal targets, and the
production data from the 96 completed horizontal wells in all three Wolfcamp zones and the Cline shale zones.
We intend to continue to make upfront investments in technology to understand the geology, geophysics and reservoir
parameters of the rock formations that define our exploration and development programs. Through comprehensive coring
programs, acquisition and evaluation of high-quality 3D seismic data and advance logging/simulation technologies, we expect
to continue to both economically de-risk our remaining property sets to the extent possible before committing to a drilling
program, and assist in the evaluation of emerging opportunities.
Enhance returns through prudent capital allocation, optimization of our development program and continued
improvements in operational and cost efficiencies. In the current commodity price environment, we have directed our capital
spending toward oil and liquids-rich drilling opportunities that provide attractive returns. We believe by emphasizing our
horizontal program, we can increase the efficiency of our resource recovery in the multiple vertically stacked producing
horizons on our acreage in our Permian-Garden City area. We initiated a development plan for a portion of our Permian-Garden
City area in order to minimize costs and maximize recoveries. We began implementing this plan in 2013, commencing with a
single zone side-by-side test and vertically stacked horizontal wellbores in multiple zones to test optimal spacing of the laterals,
both vertically and horizontally, in the four initial zones targeted for horizontal development. We are now drilling longer
laterals and optimizing our completion process to enhance the cost-efficient recovery of our resource potential. In addition,
horizontal drilling may be economic in areas where vertical drilling is currently not economical or logistically viable. We will
continue to utilize our vertical drilling program to de-risk additional acreage for all zones. Our management team is focused on
continuous improvement of our operating practices and has significant experience in successfully converting exploration
programs into cost-efficient development projects. We are the operator for 88% of our Permian-Garden City wells which allows
us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and
marketing of our production and capital allocation.
Evaluate and pursue value-enhancing acquisitions, mergers, joint ventures and divestitures. While we believe our
multi-year inventory of potential drilling locations provides us with significant growth opportunities, we continue to evaluate
strategically compelling and/or value enhancing asset acquisitions, mergers, joint ventures and divestitures. Any transaction we
pursue will either generally complement our asset base, provide an anticipated competitive economic proposition relative to our
existing opportunities or market conditions, or provide an avenue to accelerate the development of our potentially higher return
acreage and maximize the value of the total Company.
Proactively manage risk to limit downside. We continually monitor and control our business and operating risks
through various risk management practices, including maintaining a flexible financial profile, making upfront investment in
research and development as well as data acquisition, seeking multiple sales outlets, minimizing long-term contracts,
maintaining an active commodity hedging program and employing prudent safety and environmental practices.
Our competitive strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:
Significant de-risked Permian Basin acreage position and multi-year drilling inventory. From our inception in
2006 through December 31, 2013, we have completed 818 gross vertical and 98 gross horizontal wells with a success rate of
99% in our Permian-Garden City area. The 98 gross horizontal wells are comprised of 96 wells in the Upper, Middle and
Lower Wolfcamp and Cline shales and two wells in other zones. Based on our drilling results through December 31, 2013, we
believe we had confirmed the economic horizontal development potential of the equivalent of 360,000 net acres from the four
zones that includes 80,000 net acres in the Upper Wolfcamp, 80,000 net acres in the Middle Wolfcamp, 73,000 net acres in the
Lower Wolfcamp and 127,000 net acres in the Cline shale. We believe these locations provide a multi-year drilling inventory
supporting future growth in reserves, production and cash flow.
Extensive Permian technical database and expertise. We have made a substantial upfront investment to understand
the geology, geophysics and reservoir parameters of the rock formations that define our drilling and development program. We
have an extensive library of data applicable to our Permian-Garden City acreage base that includes 774 square miles of
proprietary/licensed 3D seismic (covering 95% of our acreage position), 225 proprietary petrophysical logs (fully core
calibrated), and more than 13,500 historical open-hole logs from the general area, as of December 31, 2013. We have also run
96 dipole sonic longs which play a key role in our petrophysical analysis. Approximately 470 square miles of the total 3D
seismic coverage has been merged into one volume, allowing for maximum utilization and interpretation of the data set. In
11
addition, membership in an industry core consortium has provided us access to additional petrophysical data across a larger
area outside our core Permian-Garden City acreage position. In coordination with a major oil-field consultant, we are in the
process of creating a model (utilizing a majority of the data listed above) that we anticipate will assist in developing our
Permian-Garden City acreage with the best reservoir characteristics early in the life of the field. Another important objective of
the modeling program includes how to maximize hydrocarbon recovery by utilizing the minimum required number of wells
through proper well spacing.
Significant operational control. We operate wells that represent 98% of the economic value of our proved
developed reserves as of December 31, 2013, based on a report prepared by Ryder Scott. We believe that maintaining operating
control permits us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing
ultimate hydrocarbon recoveries from mature producing basins through reservoir analysis and evaluation and continuous
improvement of drilling, completion and stimulation techniques. We expect to maintain operating control over most of our
potential drilling locations.
Owned gathering infrastructure. Our wholly-owned subsidiary, Laredo Midstream, has more than 125 miles of
pipeline in our natural gas gathering systems in the Permian Basin as of December 31, 2013. These systems and flow lines
provide greater operational efficiency and lower price differentials for our natural gas production in our liquids-rich Permian
play and enable us to coordinate our activities to connect our wells to market upon completion with minimal days waiting on
pipeline. Additionally, on a portion of our production, this provides us with multiple sales outlets through interconnection
pipelines, potentially minimizing the risks of both shut-ins awaiting pipeline connection and curtailment of downstream
pipelines. We continue to expand this concept by building out our crude oil transportation infrastructure in order to attempt to
minimize the risks of shut-in or curtailment. We have constructed crude oil truck stations in Glasscock and Reagan counties,
Texas. We have also commenced construction of a crude oil gathering system in Reagan County, Texas.
Financial strength and flexibility. We maintain a financial profile that provides operational flexibility. As of
December 31, 2013, we had $825 million available for borrowings under our Senior Secured Credit Facility and total liquidity
of $1.0 billion, with no amounts outstanding on our Senior Secured Credit Facility. As of such date, we had $1.05 billion of
total debt consisting of two series of senior unsecured notes with maturities in 2019 and 2022. We use derivatives to reduce
exposure to fluctuations in the prices of oil and natural gas. By removing a portion of the price volatility associated with future
production, we expect to mitigate, but not eliminate, the potential volatility in cash flows from operations due to fluctuations in
commodity prices.
Subsequent to December 31, 2013, we issued the new senior unsecured notes that increased our total long-term
indebtedness to $1.5 billion and decreased the amount available for borrowings under our Senior Secured Credit Facility to
$812.5 million.
Strong corporate governance and institutional investor support. Our board of directors is well qualified and
represents a meaningful resource to our management team. Our board, which is comprised of Laredo management and
representatives of Warburg Pincus, our institutional investor, as well as independent individuals, has extensive oil and natural
gas industry and general business expertise. We actively engage our board of directors on a regular basis for their expertise on
strategic, financial, governance and risk management activities. In addition, Warburg Pincus has many years of relevant
experience in financing and supporting exploration and production companies and management teams. During the last two
decades, Warburg Pincus has been the lead investor in dozens of such companies, including Broad Oak and two previous
companies operated by members of our management team.
Focus areas
Our properties are currently located in the prolific Permian region of the United States, where we leverage our
experience and knowledge to identify, exploit and acquire additional upside potential. We have been successful in delivering
repeatable results through internally generated vertical and horizontal drilling programs. We expect our Permian-Garden City
acreage, which is characterized by a high oil content, to be the primary driver of our reserves, production and cash flow growth
for the foreseeable future.
Permian Basin
The oil and liquids-rich Permian Basin, located in West Texas and Southeastern New Mexico, where we have
assembled 202,084 net acres as of December 31, 2013, is one of the most productive onshore oil and natural gas producing
regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and
hydrocarbon potential in multiple intervals. Our primary production and exploitation fairway (Permian-Garden City area) is
centered on the eastern side of the basin 35 miles east of Midland, Texas and extends 20 miles wide (east/west) and 85 miles
long (north/south) in Howard, Glasscock, Reagan, Sterling and Tom Green counties. As of December 31, 2013, we held
12
143,212 net acres in more than 300 sections in the Permian-Garden City area with an average working interest of 96% in all
Laredo-operated producing wells.
During 2013, we continued to expand our horizontal development program for the Wolfberry and Cline shales. Our
results indicate that our acreage in the Permian-Garden City area can be produced horizontally, with even stronger economic
results than our vertical program. Within the Wolfcamp, we have three distinct zones; the Upper, Middle and Lower Wolfcamp
shales, which together with the Cline shale provide at least four horizontal targets in the Permian-Garden City area. During
2013, we drilled and completed 36 horizontal wells and now have a total of 96 horizontal wells, confirming production and
attractive returns from all four zones. Today, we are continuing our drilling focus on a horizontal development and exploitation
program supported by vertical wells that help us define and optimize the horizontal targets.
As of December 31, 2013, our proprietary and industry data includes 774 square miles of proprietary/licensed 3D
seismic, 13 whole and more than 335 sidewall cores in the four zones we are currently targeting, providing extensive
production and reservoir engineering data. From our analysis of this data, we believe each of these zones has the potential to be
a stand-alone resource play with significant areal extent, the ability to produce commercial quantities of hydrocarbons and the
viability of repeatable well performance from multiple potential locations. Based on our analysis, we also believe the Wolfcamp
and Cline shales exhibit similar petrophysical attributes to other large, domestic oil and liquids-rich shale plays, such as the
Eagle Ford and Bakken.
The Wolfcamp shale resource play
The Wolfcamp shale continues to be a focus of active drilling by the industry and is encountered at depths ranging
from 7,000 to 9,000 feet under our Permian-Garden City acreage. We have been able to further define the gross Wolfcamp
shale formation into three discernible zones: the Upper, Middle and Lower Wolfcamp. Under our Permian-Garden City
acreage, each of these zones ranges in thickness between 300 and 600 feet. Based on our proprietary data and analysis, we
believe we have confirmed that all three Wolfcamp zones share many similar petrophysical and production attributes.
As of December 31, 2013, we had successfully drilled and completed 40 horizontal wells in the Upper Wolfcamp, 13
horizontal wells in the Middle Wolfcamp and six horizontal wells in the Lower Wolfcamp.
Upper Wolfcamp. As of December 31, 2013, we estimated that 80,000 net acres of our Permian-Garden City area
had been de-risked for horizontal Upper Wolfcamp development. In the Upper Wolfcamp, we have identified a facies change
progressing from west to east across our acreage, with the shale becoming increasingly carbonate. To date we have drilled and
completed more wells in the southern third of our de-risked Upper Wolfcamp acreage, while continuing to explore and develop
the entire area.
Middle and Lower Wolfcamp. In the Middle and Lower Wolfcamp, we continue to expand our evaluation efforts
across our acreage. Production from our vertical drilling program has confirmed that both the Middle and Lower Wolfcamp
zones underlie the majority of our acreage. As with the Upper Wolfcamp, there appears to be a similar facies change in these
zones. As of December 31, 2013, we had drilled and completed 13 horizontal wells in the Middle Wolfcamp zone and six
horizontal wells in the Lower Wolfcamp zone. As of the same date we estimated that 80,000 net acres in the Middle Wolfcamp
and 73,000 net acres in the Lower Wolfcamp had been de-risked for horizontal development. Through the combination of our
drilling activities, the initial production results from these wells and our extensive technical database, we will continue our
efforts to fully evaluate the potential of both the Middle and Lower Wolfcamp over our whole Permian-Garden City acreage
position.
The Cline shale resource play
As of December 31, 2013, we estimated that 127,000 net acres of our Permian-Garden City area had been de-risked
for horizontal Cline development. In 2013, we successfully drilled and completed three horizontal wells and now have a total of
37 horizontal wells in the Cline shale.
We first recognized the potential of the Cline shale in 2008, took our first Cline cores in 2009 and drilled our first
horizontal well in the formation in early 2010. We are now in the horizontal development phase on this de-risked acreage. We
believe the petrophysical data indicates that this is a repeatable economic resource play, and we continue to delineate and define
the Cline potential on our remaining Permian-Garden City acreage. Industry activity relative to the Cline shale has also been
initiated with several horizontal wells being drilled and/or permitted immediately north and east of our Permian-Garden City
acreage position.
The Cline shale is encountered at a depth of 9,000 to 9,500 feet in our Permian-Garden City acreage. Our proprietary
petrophysical data indicates that the Cline is a laterally extensive, high-quality, over-pressured source rock with an abundance
of oil-prone organic matter and high generation potential. Cline conventional cores contain numerous vertical extension
13
fractures that are partially open, significantly enhancing system permeability across the matrix. Multiple thermal maturity
indices show the Cline to be in a "peak liquids" stage in the late oil to early gas/condensate window. As our drilling and data
acquisition programs progress, we are beginning to define those areas that show commonality in terms of reservoir type, quality
and repeatability.
Other areas
On August 1, 2013 we completed the sale of our assets in the Anadarko Basin in the Texas Panhandle and Western
Oklahoma. Included in this sale were 43,450 net acres in the Central Texas Panhandle and 21,000 net acres in the eastern end of
the Anadarko Basin, in Caddo, Grady and Comanche counties, Oklahoma.
New Ventures
In addition to our Permian Basin acreage, we continue to evaluate new opportunities in other areas within our core
operating regions, which we refer to as our "New Ventures."
The Dalhart Basin is located on the western side of the Texas Panhandle. On December 20, 2013 we completed the
sale of 37,000 net acres of our position in the Dalhart Basin. As of December 31, 2013, we held 50,000 net acres in the Dalhart
Basin, which is included in New Ventures.
In addition, as of December 31, 2013, we held 29,459 net acres in other New Venture areas.
Our operations
Estimated proved reserves
Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas
liquids in our natural gas is included in the wellhead natural gas price. In this Annual Report, the information with respect to
our estimated proved reserves presented below has been prepared by Ryder Scott, our independent reserve engineers, in
accordance with the rules and regulations of the SEC applicable to the periods presented. Our net proved reserves were
estimated at 203,615 MBOE as of December 31, 2013, of which 35% were classified as proved developed reserves, and 55%
are attributable to oil reserves. The following table presents summary data for each of our core operating areas as of
December 31, 2013. Our estimated proved reserves as of December 31, 2013 assume our ability to fund the capital costs
necessary for their development and are affected by pricing assumptions. In addition, we may not be able to raise the amounts
of capital that would be necessary to drill a substantial portion of our proved undeveloped reserves. See "Item 1A. Risk Factors
—Risks related to our business—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and
natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to
decreased earnings, losses or impairment of oil and natural gas assets."
Area:
Permian Basin ....................................................................................................................
New Ventures(1) ..................................................................................................................
Total.................................................................................................................................
(MBOE)
203,564
51
203,615
99%
1%
100%
_______________________________________________________________________________
(1) Includes Dalhart Basin and other New Ventures.
As of December 31, 2013
Proved reserves
% of total
14
The following table sets forth more information regarding our estimated proved reserves as of December 31, 2013 and
2012. Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves as of December 31, 2013 and
2012. The reserve estimates as of December 31, 2013 and 2012 were prepared in accordance with the SEC's rules regarding oil
and natural gas reserve reporting currently in effect. The information does not give any effect to our commodity hedges.
Estimated proved reserves:
Oil and condensate (MBbl).............................................................................................................
Natural gas (MMcf) ........................................................................................................................
Total estimated proved reserves (MBOE) ......................................................................................
Proved developed producing (MBOE) ...........................................................................................
Proved developed non-producing (MBOE)....................................................................................
Proved undeveloped (MBOE) ........................................................................................................
Percent developed...........................................................................................................................
_______________________________________________________________________________
(1) Includes proved reserves attributable to the acreage sold in the Anadarko Basin Sale.
As of December 31,
2013
2012(1)
111,498
552,702
203,615
67,968
3,757
98,141
542,946
188,632
76,777
4,713
131,890
107,142
35%
43%
Technology used to establish proved reserves. Under the SEC rules, proved reserves are those quantities of oil and
natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically
producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and
government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or
natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that
have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other
evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more
technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably
certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and
Ryder Scott, our independent reserve engineers, employed technologies that have been demonstrated to yield results with
consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but
are not limited to, open hole logs, core analyses, geologic maps, available downhole and production data and seismic data.
Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves,
material balance calculations or other performance relationships. Reserves attributable to producing wells with limited
production history and for undeveloped locations were estimated using pore volume calculations and performance from
analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be
analogous based on production performance from the same formation and completion using similar techniques.
Qualifications of technical persons and internal controls over reserves estimation process. In accordance with the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated 100%
of our proved reserve information as of December 31, 2013 and 2012 included in this Annual Report. The technical persons
responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence,
objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our
independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves
estimation process. Our technical team meets regularly with representatives of Ryder Scott to review properties and discuss
methods and assumptions used in Ryder Scott's preparation of the year-end reserves estimates. The Ryder Scott reserve report is
reviewed with representatives of Ryder Scott and our internal technical staff before dissemination of the information.
Additionally, our senior management reviews the Ryder Scott reserve report.
Gary B. Smallwood, our Vice President of Reservoir Modeling and Field Development Planning, is the technical
person primarily responsible for overseeing the preparation of our reserves estimates. He has more than 38 years of practical
experience with 30 years of this experience being in the estimation and evaluation of reserves. He has a Bachelors of Science
15
degree in Chemical Engineering and is a life member in good standing of the Society of Petroleum Engineers. Mr. Smallwood
reports directly to our President and Chief Operating Officer. Reserves estimates are reviewed and approved by our senior
engineering staff with final approval by our President and Chief Operating Officer and certain other members of our senior
management. Our senior management also reviews our independent engineers' reserves estimates and related reports with our
senior reservoir engineering staff and other members of our technical staff.
Proved undeveloped reserves
Our proved undeveloped reserves, reported on a two-stream basis, increased from 107,142 MBOE as of December 31,
2012 to 131,890 MBOE as of December 31, 2013. During 2013, 5,782 MBOE of proved undeveloped reserves from 25
locations were converted to proved developed reserves. New proved undeveloped reserves of 47,643 MBOE were added
during the year, with 96% coming from new horizontal Upper, Middle and Lower Wolfcamp and Cline locations. Negative
revisions of 11,944 MBOE were due to the combined effect of removing 174 proved locations and the net effect of
redetermining 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and
short horizontal laterals. They were replaced with longer horizontal laterals to better align with future drilling plans.
Estimated total future development and abandonment costs related to the development of proved undeveloped reserves
as shown in our December 31, 2013 reserves report are $2.2 billion. Based on this report, the capital estimated to be spent in
2014, 2015, 2016, 2017 and 2018 to develop the proved undeveloped reserves is $359 million, $482 million, $558 million,
$499 million and $232 million, respectively. All of the proved undeveloped locations are expected to be drilled within a five-
year period.
16
Production, revenues and price history
The following table sets forth information regarding production, revenues and realized prices and production costs for
the years ended December 31, 2013, 2012 and 2011. Our reserves and production are reported in two streams: crude oil and
liquids-rich natural gas. The economic value of the natural gas liquids in our liquids-rich natural gas is included in the wellhead
natural gas price. For additional information on price calculations, see the information in "Item 7. Management's discussion and
analysis of financial condition and results of operations."
(unaudited)
Production data:
Oil (MBbl)..........................................................................................................
Natural gas (MMcf)............................................................................................
Oil equivalents (MBOE)(1) .................................................................................
Average daily production (BOE/D)(1).................................................................
Revenues (in thousands):
Oil.......................................................................................................................
Natural gas..........................................................................................................
Average sales prices without hedges:
Benchmark oil ($/Bbl)(2).....................................................................................
Realized oil ($/Bbl)(3) .........................................................................................
Benchmark natural gas ($/MMBtu)(2) ................................................................
Realized natural gas ($/Mcf)(3) ...........................................................................
Average price ($/BOE).......................................................................................
Average sales prices with hedges(4):
Oil ($/Bbl) ..........................................................................................................
Natural gas ($/Mcf) ............................................................................................
Average price ($/BOE).......................................................................................
Average cost per BOE:
Lease operating expenses ...................................................................................
Production and ad valorem taxes .......................................................................
Depletion, depreciation and amortization ..........................................................
General and administrative(5)..............................................................................
_______________________________________________________________________________
$
$
$
$
$
$
$
$
$
$
$
$
$
$
For the years ended December 31,
2013
2012
2011
5,487
34,348
11,211
30,716
494,676
170,168
97.97
90.16
3.65
4.95
59.29
88.68
4.98
58.66
7.06
3.78
20.87
8.00
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4,775
39,148
11,300
30,874
414,932
168,637
94.20
86.89
2.80
4.31
51.65
85.59
4.92
53.22
5.96
3.33
21.33
5.50
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3,368
31,711
8,654
23,709
306,481
199,774
95.01
91.00
4.02
6.30
58.50
88.16
6.59
58.47
5.00
3.70
20.12
5.90
(1) The volumes presented for the years ended December 31, 2013, 2012 and 2011 are based on actual results and are
not calculated using the rounded numbers in the table above.
(2) Benchmark oil prices are the simple average of the daily settlement price for NYMEX West Texas Intermediate
Light Sweet Crude Oil each month for the period indicated. Benchmark natural gas prices are the simple arithmetic
average of the last day settlement price for NYMEX natural gas each month for the period indicated.
(3) Realized crude oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for
natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions
and other factors affecting the price at the wellhead.
(4) Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our
calculation of such after effects include current period settlements of matured derivative instruments in accordance
with the applicable generally accepted accounting principles in the United States of America (“GAAP”) and an
adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in
the period. The prices presented are based on actual results and are not calculated using the rounded numbers
presented in the table above
17
(5) General and administrative includes non-cash stock-based compensation of $21.4 million, $10.1 million and $6.1
million for the years ended December 31, 2013, 2012 and 2011, respectively. Excluding stock-based compensation
from the above metric results in average general and administrative cost per BOE of $6.09, $4.61 and $5.19 for the
years ended December 31, 2013, 2012 and 2011, respectively.
Productive wells
The following table sets forth certain information regarding productive wells in each of our core areas as of December
31, 2013. Our wells are classified as oil wells, all of which also produce natural gas, condensate and natural gas liquids. Wells
are classified as oil or gas wells according to the predominant production stream, except that a well with multiple completions
is classified as an oil well if one or more of the completions is an oil completion. We only have two wells that primarily
produce gas; however, they both also have completions that produce oil. We also own royalty and overriding royalty interests in
a small number of wells in which we do not own a working interest.
Total producing wells
Gross
Vertical
Horizontal
Total
Net
Permian Basin:
Operated Permian-Garden City.................................................
Non-Operated Permian Garden City.........................................
Operated Permian-China Grove(1).............................................
Operated New Ventures(2) .............................................................
Total .........................................................................................
838
122
1
1
962
_______________________________________________________________________________
(1) Located primarily in Mitchell County, Texas.
(2) Includes Dalhart Basin and other New Ventures.
Acreage
97
1
1
—
99
935
123
2
1
902
36
2
1
1,061
941
Average
WI %
96%
29%
99%
95%
89%
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own
an interest as of December 31, 2013 for each of our core operating areas, including acreage held by production ("HBP"). A
majority of our developed acreage is subject to liens securing our Senior Secured Credit Facility.
Developed acres
Undeveloped acres
Total acres
Gross
Net
Gross
Net
Gross
Net
Permian Basin:
Permian-Garden City.......
Permian-China Grove......
New Ventures(1) ...................
Total................................
102,355
93,149
478
640
454
502
75,968
74,737
89,495
50,063
58,418
79,641
178,323
143,212
75,215
90,135
58,872
80,143
103,473
94,105
240,200
188,122
343,673
282,227
%
HBP
65%
1%
1%
33%
_______________________________________________________________________________
(1) Includes Dalhart Basin and other New Ventures.
18
Undeveloped acreage expirations
The following table sets forth the gross and net undeveloped acreage in our core operating areas as of December 31,
2013 that will expire over the next four years unless production is established within the spacing units covering the acreage or
the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
2014
2015
2016
2017
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Permian Basin:
Permian-Garden City..............
Permian-China Grove.............
New Ventures(1) ..........................
Total.......................................
11,319
21,734
39,981
73,034
10,929
16,692
35,825
63,446 103,656
23,596
48,318
31,742
15,214
38,083
26,804
80,101
5,409
4,686
2,741
12,836
2,515
3,643
2,411
8,569
—
—
10,841
10,841
—
—
10,714
10,714
_______________________________________________________________________________
(1) Includes Dalhart Basin and other New Ventures.
Drilling activity
The following table summarizes our drilling activity for the years ended December 31, 2013, 2012 and 2011. Gross
wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.
Development wells:
Productive ..........................................................................
Dry .....................................................................................
Total development wells..................................................
Exploratory wells:
Productive ..........................................................................
Dry .....................................................................................
Total exploratory wells....................................................
Marketing and major customers
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
171
—
171
2
—
2
127.2
—
127.2
2.0
—
2.0
199
—
199
1
1
2
183.2
—
183.2
1.0
0.9
1.9
260
—
260
2
—
2
233.2
—
233.2
1.4
—
1.4
We market the majority of production from properties we operate for both our account and the account of the other
working interest owners in our operated properties. We sell substantially all of our production to a variety of purchasers under
contracts ranging from one month to several years, all at market prices. We normally sell production to a relatively small
number of customers, as is customary in the exploration, development and production business. We have committed a portion
of our Permian crude oil production under firm transportation agreements which will enhance our ability to move our crude oil
out of the Permian Basin and give us access to potentially more favorable Gulf Coast pricing.
As of December 31, 2013, we were committed to deliver the following fixed quantities of production under certain
contractual arrangements that specify the delivery of a fixed and determinable quantity.
Oil and condensate (MBbl)..........................................................
Natural gas (MMcf) .....................................................................
Total (MBOE)..............................................................................
100,314
70,192
112,013
6,570
1,170
6,765
9,490
3,393
10,055
Total
2014
2015
2016
11,802
4,796
12,601
2017 and
beyond
72,453
60,833
82,591
Subsequent to December 31, 2013, we entered into additional agreements to deliver fixed quantities of production. As
of February 26, 2014, we were committed to deliver the following fixed quantities of production under certain contractual
19
arrangements that specify the delivery of a fixed and determinable quantity.
Oil and condensate (MBbl)..........................................................
Natural gas (MMcf) .....................................................................
Total (MBOE)..............................................................................
131,948
70,192
143,646
6,570
1,170
6,765
9,490
3,393
10,055
Total
2014
2015
2016
14,235
4,796
15,034
2017 and
beyond
101,653
60,833
11,791
We expect to fulfill our delivery commitments over the next three years with production from our proved reserves. We
expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved undeveloped reserves.
Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and
we expect such reserves will continue to satisfy our future commitments. However, should our proved reserves not be sufficient
to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.
Based on the current demand for oil and natural gas and the availability of alternate purchasers, we believe that the
loss of any one of our major purchasers would not have a material adverse effect on our financial condition and results of
operations. For information regarding each of our customers that accounted for 10% or more of our oil and natural gas revenues
during the last three calendar years, see Note I in our audited consolidated financial statements included elsewhere in this
Annual Report. See "Item 1A. Risk Factors—Risks related to our business—The inability of our significant customers to meet
their obligations to us may materially adversely affect our financial results."
Title to properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted
industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record
title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing
properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to
burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may
include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under
applicable laws, development obligations under natural gas leases, or net profits interests.
Oil and natural gas leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the
mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other
leasehold burdens on our properties generally range from 12.5% to 25%, resulting in a net revenue interest to us generally
ranging from 75% to 87.5%. As of December 31, 2013, 33% of our leasehold acreage was HBP.
Seasonality
Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer
and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In
addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter
requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase
competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and
increase costs or delay our operations.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that
have greater resources than we do, especially in our focus areas. Many of these companies not only explore for and produce oil
and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for productive properties and exploratory locations or define,
evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit and
may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a
greater ability to continue exploration and development activities during periods of low market prices. Our larger competitors
may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than
we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover
reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many
companies in our industry, we may be at a disadvantage in bidding for exploratory and producing properties.
20
Hydraulic fracturing
We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete.
Hydraulic fracturing is a necessary part of the completion process for our producing properties in Texas because our properties
are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. We are
currently conducting hydraulic fracturing activity in the completion of both our vertical and horizontal wells in the Permian
Basin. While hydraulic fracturing is not required to maintain any of our leasehold acreage that is currently held by production
from existing wells, it will be required in the future to develop the proved non-producing and proved undeveloped reserves
associated with this acreage. Nearly all of our proved developed non-producing and proved undeveloped reserves associated
with future drilling, recompletion and refracture stimulation projects require hydraulic fracturing.
We have and continue to follow standard industry practices and applicable legal requirements. State and federal
regulators (including the U.S. Bureau of Land Management on federal acreage) impose requirements on our operations
designed to ensure protection of human health and the environment. These protective measures include setting surface casing at
a depth sufficient to protect fresh water zones, and cementing the well to create a permanent isolating barrier between the
casing pipe and surrounding geological formations. It is believed that this well design effectively eliminates a pathway for the
fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the
production casing is pressure tested prior to perforating the new completion interval.
Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic
fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string.
Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or
annular pressure.
Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations.
Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents
in the fracturing fluid are managed and used in accordance with applicable requirements. In accordance with Texas regulations,
we report the constituents of the hydraulic fracturing fluids utilized in our well completions on FracFocus (www.fracfocus.org).
Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it
by discharge into approved disposal wells, so as to minimize the potential for impact to nearby surface water. We currently do
not discharge water to the surface. We are in the process of testing recycled flowback/produced water in our fracing operations,
and are evaluating the performance of the limited number of wells in which we have used this process to determine if there is
any impact on productivity.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related
environmental matters, please read "—Regulation of environmental and occupational health and safety matters—Water and
other waste discharges and spills." For related risks to our stockholders, please read "Item 1A. Risk Factors—Risks related to
our business—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could prohibit projects or
result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic
fracturing in our business."
Regulation of the oil and natural gas industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas
production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations.
The state of Texas has statutory provisions regulating the exploration for and production of oil and natural gas, including
provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the
method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and
disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to
various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration
units, the number of wells which may be drilled in an area and the pooling of crude oil and natural gas wells, as well as
regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability
or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the
industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the
natural gas industry are regularly considered by Congress, the states, the Environmental Protection Agency ("EPA"), Federal
Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become
effective.
We believe we are in substantial compliance with currently applicable laws and regulations and that continued
substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows
21
or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents
may occur or past non-compliance with environmental laws or regulations may be discovered and such laws and regulations
are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impacts of compliance.
Regulation of production of oil and natural gas
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes,
rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling
bonds and reports concerning operations. The State of Texas has regulations governing conservation matters, including
provisions for the pooling of oil and natural gas properties, including the permitting of "allocation wells," the establishment of
maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and plugging and
abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our
wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such
regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the
production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Texas further regulates drilling and
operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled and the plugging and abandonment of wells. State laws also govern a
number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the
size of drilling and spacing units or proration units and the density of wells that may be drilled, pooling of oil and natural gas
properties and establishment of maximum rates of production from oil and natural gas wells. Texas further has the power to
prorate production to the market demand for oil and natural gas. The failure to comply with these rules and regulations can
result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory
requirements and restrictions that affect our operations.
Regulation of environmental and occupational health and safety matters
Our operations are subject to numerous stringent federal, state and local statutes and regulations governing the
discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and
safety. Numerous governmental agencies, such as the EPA, issue regulations, which often require difficult and costly
compliance measures, the noncompliance with which carries substantial administrative, civil and criminal penalties and may
result in injunctive obligations to remediate noncompliance. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the
environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of
water used in the drilling, completion and production process, limit or prohibit drilling activities in certain areas and on certain
lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent or
mitigate pollution from current or former operations such as plugging abandoned wells or closing earthen pits, result in the
suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed
and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In
addition, these laws and regulations may restrict the rate of production. Certain of these laws and regulations impose strict and
joint and several liability penalties that could impose liability upon us regardless of fault. Public interest in the protection of the
environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation
and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and
consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and to the extent laws are
enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste
handling, disposal and clean-up requirements, our business and prospects, as well as the oil and natural gas industry in general,
could be materially adversely affected.
Hazardous substance and waste handling
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous
substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage,
treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several
liability for the investigation and remediation of affected areas where hazardous substances may have been released or
disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA
or the Superfund law, and comparable state laws, impose liability, without regard to fault or the legality of the original conduct,
on certain classes of persons deemed "responsible parties." These persons include current owners or operators of the site where
a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release
or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances
found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of
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certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the
public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the
"petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle
hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as
a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these
hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous
substances at our properties by prior owners or operators or other third parties. Finally, it is not uncommon for neighboring
landowners and other third parties to file common law based claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.
The Oil Pollution Act of 1990 (the "OPA") is the primary federal law imposing oil spill liability. The OPA contains
numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States,
including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must
maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under
the OPA, strict, joint and several liability may be imposed on "responsible parties" for all containment and clean-up costs and
certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface
waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the
exclusive economic zone of the United States. A "responsible party" includes the owner or operator of an onshore facility. The
OPA establishes a liability limit for onshore facilities of $350 million. These liability limits may not apply if: a spill is caused
by a party's gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or
operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state
statutes that impose liabilities with respect to oil spills. We also generate solid wastes, including hazardous wastes, which are
subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state
statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage,
treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA's
hazardous waste regulations. It is possible, however, that these wastes, which could include wastes currently generated during
our operations, will be designated as "hazardous wastes" in the future and, therefore, be subject to more rigorous and costly
disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and
natural gas exploration and production wastes as "hazardous wastes." Any such changes in the laws and regulations could have
a material adverse effect on our maintenance capital expenditures and operating expenses.
We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state
and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations
required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are
presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration
and production wastes could increase our costs to manage and dispose of such wastes.
Water and other waste discharges and spills
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water
Act ("SDWA"), the OPA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants,
including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated
waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge
and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S.
Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and
production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be
associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as
for monitoring and sampling the storm water runoff from certain of our facilities. The State of Texas also maintains
groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining
permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit
the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance
costs. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any
unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for
the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and
maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are
required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in
connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct
our operations, and we believe we are in substantial compliance with their terms.
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Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons from tight formations. The
process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock
and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions, the
EPA recently asserted federal regulatory authority over the process under the SDWA's Underground Injection Control ("UIC")
Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing
operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production
activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits
the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC
Program permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document
describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the
hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we
maintain acreage, the EPA is encouraging state programs to review and consider use of this permit guidance. On November 3,
2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study
will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a
progress report in December 2012, and expects to release a draft report for public comment and peer review in 2014. In
addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal
regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on
October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the
hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some
resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other
pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act
prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be
injected into permitted disposal wells, transported to public or private treatment facilities for treatment, or recycled. The EPA
asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to treat the
wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to
pre-treat wastewater before transferring it to treatment facilities. A proposed rule is expected in April 2014. We cannot predict
the impact that these standards may have on our business at this time, but these standards could have a material impact on our
business, financial condition and results of operation.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing
in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For
example, pursuant to legislation adopted by the State of Texas in June 2011, beginning February 1, 2012, companies were
required to disclose to the RRC and the public the chemical components used in the hydraulic fracturing process, as well as the
volume of water used. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the
performance of well drilling in general and/or hydraulic fracturing in particular. Furthermore, on May 16, 2013, the United
States Department of the Interior ("DOI") issued a revised proposed rule that seeks to require companies operating on federal
and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet
certain construction standards and (iii) establish site plans to manage flowback water. Under current federal law, there is no
requirement for operators to disclose the use of such chemicals, although Laredo has already commenced similar disclosure
with state regulators.
If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws
could make it more difficult or costly for us to drill and produce from tight formations as well as make it easier for third parties
opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the
federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more
stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and
abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well
as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure
to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not
possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic
fracturing is enacted into law.
Air emissions
The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many
sources, including compressor stations, through the issuance of permits and the imposition of other requirements. In addition,
the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified
sources. In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and
storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for
Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured
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gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels,
natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in volatile organic
compounds ("VOC") emitted by requiring the use of reduced emission completions or “green completions” on all
hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of
modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1,
2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental
community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that may be responsive to
some of these requests. On September 23, 2013, the EPA finalized the portion of the rule addressing VOC emissions from
storage tanks, including a phase-in period and an alternative emissions limit for older tanks. These standards, as well as any
future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of
existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit
requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements
could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal
enforcement actions.
We have incurred additional capital expenditures to insure compliance with these new regulations as they come into
effect. We may also be required to incur additional capital expenditures in the next few years for air pollution control
equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which
may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil
and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that
we hold all necessary and valid construction and operating permits for our current operations.
Regulation of "greenhouse gas" emissions
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse
gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and
other climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions
of GHGs. One bill approved by the House of Representatives in June 2009, known as the American Clean Energy and Security
Act of 2009, would have required an 80% reduction in emissions of GHGs and almost one-half of the states have already taken
legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional
GHG cap and trade programs, although in recent years some states have scaled back their commitment to GHG initiatives.
Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers
of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their
annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG
emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of
allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities
to purchase a certain percentage of their energy from renewable fuel sources.
In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs
present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA,
contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to
proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions
of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding
possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in
January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the
"tailoring rule") in May 2010, and it became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court
granted review of certain issues related to the EPA's authority to regulate such emissions from stationary sources. Oral
arguments on the issues before the Supreme Court were heard on February 24, 2014, and a decision is expected by July 2014.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission
sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011
for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to
include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires
reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring
in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed
GHG rule that, if finalized, would set NSPS for new coal-fired and natural-gas fired power plants.
The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased
operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply
with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or
refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.
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Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business,
financial condition and results of operations.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA") and
comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard
communication standard requires that information be maintained about hazardous materials used or produced in our operations
and that this information be provided to employees, state and local government authorities and citizens. We believe that our
operations are in substantial compliance with the OSHA requirements.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental
Policy Act ("NEPA"). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major
agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency
prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If
impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available
for public review and comment. All of our current exploration and production activities, as well as proposed exploration and
development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This
environmental impact assessment process has the potential to delay the development of oil and natural gas projects.
Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
Endangered Species Act
The Endangered Species Act ("ESA") was established to protect endangered and threatened species. Pursuant to the
ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that
species' habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations
on federal oil and natural gas leases in areas where certain species that are listed as threatened or endangered and where other
species, such as the sage grouse, potentially could be listed as threatened or endangered under the ESA exist. The U.S. Fish and
Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a
threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to
federal land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a
portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to
operating restrictions or bans in the affected areas, which could adversely impact the value of our leases.
Summary
In summary, we believe we are in substantial compliance with currently applicable environmental laws and
regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements,
there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in
connection with complying with environmental laws or environmental remediation matters in 2012 or 2013.
Disclosures required pursuant to Section 13(r) of the Securities Exchange Act of 1934
Under the Iran Threat Reduction and Syrian Human Rights Act of 2012 (the “Act”), which added Section 13(r) of the
Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined
in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities, transactions or dealings relating to
Iran or with certain individuals or entities targeted by United States' economic sanctions during the period covered by the
report. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with
applicable law. Neither we nor any of our controlled affiliates or subsidiaries knowingly engaged in any of the specified
activities relating to Iran or otherwise engaged in any activities associated with Iran during the reporting period. However,
because the SEC defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that
controlled us or is under common control with us.
The description of the activities below has been provided to us by Warburg Pincus, affiliates of which: (i) beneficially
own more than 10% of our outstanding common stock and are members of our board of directors and (ii) beneficially own
more than 10% of the equity interests of, and have the right to designate members of the board of directors of, Endurance
International Group (“EIG”) and Santander Asset Management Investment Holdings Limited (“SAMIH”). EIG and SAMIH
may therefore be deemed to be under "common control" with us; however, this statement is not meant to be an admission that
common control exists.
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As to EIG:
The disclosure below relates solely to activities conducted by EIG and its affiliates. The disclosure does not relate to
any activities conducted by Laredo or by Warburg Pincus and does not involve our or Warburg Pincus' management. Neither
Laredo nor Warburg Pincus had any involvement in or control over the disclosed activities of EIG, and neither Laredo nor
Warburg Pincus has independently verified or participated in the preparation of the disclosure. Neither Laredo nor Warburg
Pincus is representing as to the accuracy or completeness of the disclosure nor do we or Warburg Pincus undertake any
obligation to correct or update it.
Laredo understands that EIG’s affiliates intend to disclose in their next annual or quarterly SEC report that:
“EIG's business activities are subject to various restrictions under U.S. export controls and trade and economic
sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade
sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control, or OFAC. If EIG fails to
comply with these laws and regulations, EIG could be subject to civil or criminal penalties and reputational harm. In addition,
if EIG's third-party resellers fail to comply with these laws and regulations in their dealings, EIG could face potential liability
or penalties for violations. Furthermore, U.S. export control laws and economic sanctions laws prohibit certain transactions
with U.S. embargoed or sanctioned countries, governments, persons and entities.
Although EIG takes precautions to prevent transactions with U.S. sanctions targets, EIG has in the past identified
limited instances of non-compliance with these rules and believes EIG has taken appropriate corrective actions in such
instances. For example, on May 1, 2013, during a routine compliance scan of EIG's new and existing subscriber accounts, EIG
discovered a new subscriber account that was created on April 6, 2013 with information matching ORT France, identified by
OFAC as a Specially Designated National, or SDN, under the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. EIG
had charged the subscriber $114.10 for web hosting and domain name registration services at the time the account was opened
and without knowledge of any SDN issue. Upon discovery of the potential SDN match, EIG promptly suspended the subscriber
account, deactivated the website, locked the domain name to prevent it from being transferred and ceased providing services to
the subscriber. EIG also promptly reported the potential SDN match to OFAC. To date, EIG has not received any
correspondence from OFAC regarding the matter.
Although EIG has implemented compliance measures that are designed to prevent transactions with U.S. sanction
targets, there is risk that in the future EIG or its resellers could provide its solutions or services to such targets despite such
compliance measures. This could result in negative consequences to EIG, including government investigations, penalties and
reputational harm.
Changes in EIG's solutions or changes in export and import regulations may create delays in the introduction and sale
of EIG's solutions in international markets, prevent EIG's subscribers with international operations from deploying its solutions
or, in some cases, prevent the export or import of EIG's solutions to certain countries, governments or persons altogether. Any
change in export or import regulations, shift in the enforcement or scope of existing regulations, or change in the countries,
governments, persons or technologies targeted by such regulations, could result in decreased use of EIG's solutions or
decreased ability to export or sell its solutions to existing or potential subscribers with international operations. Any decreased
use of EIG's solutions or limitation on its ability to export or sell its solutions could adversely affect EIG's business, financial
condition and operating results.”
As to SAMIH:
The disclosure below relates solely to activities conducted by SAMIH and its non-U.S. affiliates. The disclosure does
not relate to any activities conducted by Laredo or by Warburg Pincus and does not involve our or Warburg Pincus’
management. Neither Laredo nor Warburg Pincus has had any involvement in or control over the disclosed activities of
SAMIH, and neither Laredo nor Warburg Pincus has independently verified or participated in the preparation of the disclosure.
Neither Laredo nor Warburg Pincus is representing to the accuracy or completeness of the disclosure nor do we or Warburg
Pincus undertake any obligation to correct or update it.
Laredo understands that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that an
Iranian national, resident in the U.K., who is currently designated by the U.S. and the U.K. under the Iran Sanctions regime,
holds two investment accounts with Santander Asset Management UK Limited, a subsidiary of SAMIH and part of the Banco
Santander group. The accounts have remained frozen throughout 2013. The investment returns are being automatically
reinvested, and no disbursements have been made to the customer. Total revenue in connection with the investment accounts in
2013 was £247 and net profits in 2013 were negligible relative to the overall profits of Banco Santander, S.A.
Employees
As of December 31, 2013, we had 340 full-time employees. We also employed a total of 31 contract personnel who
assist our full-time employees with respect to specific tasks and perform various field and other services. Our future success
will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective
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bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees
to be satisfactory.
Our offices
Our executive offices are located at 15 W. Sixth Street, Suite 1800, Tulsa, Oklahoma 74119, and the phone number at
this address is (918) 513-4570. We also lease corporate offices in Midland and Dallas, Texas.
Available information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You
may read and copy any documents filed by us with the SEC at the SEC's Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at
the SEC's website at http://www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange under the symbol "LPI." Our reports, proxy
statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20
Broad Street, New York, New York 10005.
We also make available on our website (http://www.laredopetro.com) all of the documents that we file with the SEC, free
of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Conduct and
Business Ethics, Code of Ethics For Senior Financial Officers, Corporate Governance Guidelines and the charters of our audit
committee, compensation committee and nominating and corporate governance committee are also available on our website
and in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at
our executive office at 15 W. Sixth Street, Suite 1800, Tulsa, Oklahoma 74119. Information contained on our website is not
incorporated by reference into this Annual Report. We intend to disclose on our website any amendments or waivers to our
Code of Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K.
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Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this
Annual Report, were actually to occur, our business, financial condition or results of operations could be materially adversely
affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks
described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider
immaterial may also adversely affect us.
Risks related to our business
Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect
our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and
financial commitments.
The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to
capital and future rate of growth. Oil and natural gas are commodities, and therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil and natural gas has
been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the
levels of our production, depend on numerous factors beyond our control. These factors include the following:
• worldwide and regional economic and financial conditions impacting the global supply and demand for oil and
natural gas;
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the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;
political conditions in or affecting other oil and natural gas-producing countries, including the current conflicts in
the Middle East, and conditions in South America, Africa and Russia;
the level of global oil and natural gas exploration and production;
future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
the level of global oil and natural gas inventories;
prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
localized and global supply and demand fundamentals and transportation availability;
• weather conditions;
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technological advances affecting energy consumption;
the price and availability of alternative fuels; and
domestic, local and foreign governmental regulation and taxes.
Lower oil and natural gas prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed
capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves as existing reserves
are depleted. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our
exploration, development and exploitation projects. This may result in our having to make significant downward adjustments to
our estimated proved reserves. As a result, a substantial or extended decline in oil and natural gas prices may materially and
adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital
expenditures.
Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on
satisfactory terms or at all.
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have
funded our capital expenditures through a combination of cash flows from operations, capital contributions, borrowings on our
Senior Secured Credit Facility, equity offerings and proceeds from our senior unsecured notes. We do not have commitments
from anyone to contribute capital to us. Future cash flows are subject to a number of variables, including the level of
production from existing wells, prices of oil and natural gas and our success in developing and producing new reserves. If our
cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the
additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on
terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating
to exploration and development of our prospects, which in turn could lead to a decline in our oil and natural gas production or
reserves and, in some areas, a loss of properties.
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Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect
our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploration, exploitation,
development and production activities. Our oil and natural gas exploration, exploitation, development and production activities
are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and
natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in
part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering
studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty
involved in these processes, see "—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and
natural gas prices, or negative revisions to reserves estimates or assumptions as to future oil and natural gas prices, may lead to
decreased earnings, losses or impairment of oil and natural gas assets." In addition, our cost of drilling, completing and
operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled
drilling projects, including the following:
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delays imposed by or resulting from compliance with regulatory and contractual requirements and related
lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment and qualified personnel;
equipment failures or accidents;
fires and blowouts;
adverse weather conditions, such as hurricanes, blizzards and ice storms;
declines in oil and natural gas prices;
limited availability of financing at acceptable rates;
title problems; and
limitations in the market for oil and natural gas.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal wells could
prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the
significance of hydraulic fracturing and water disposal wells in our business.
Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations.
The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding
rock and stimulate production. Nearly all of our proved non-producing and proved undeveloped reserves associated with future
drilling, recompletion and refracture stimulation projects require hydraulic fracturing. If we are unable to apply hydraulic
fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill
and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material
adverse effect on our future business, financial condition, operating results and prospects.
The process is typically regulated by state oil and gas commissions. The U.S. Environmental Protection Agency (the
"EPA"), however, recently asserted federal regulatory authority over hydraulic fracturing under the federal Safe Drinking Water
Act's ("SDWA") Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities
to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts
hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC
permit. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas hydraulic fracturing
activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting
fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel
fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II
programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-
mentioned draft guidance. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic
Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities
designed to generate future data. The EPA issued a progress report in December 2012, held several technical workshops during
2013, and expects to release a draft report for public comment and peer review in 2014.
In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and
storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for
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Hazardous Air Pollutants ("NESHAP") programs. The rule includes NSPS standards for completions of hydraulically fractured
gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels,
natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a
number of the requirements did not take immediate effect. The rule established a phase-in period to allow for the manufacture
and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and
operators of gas wells must either flare their emissions or use emissions reduction technology called "green completions"
technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green
completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning August 16,
2012, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three
years and 60 days after the August 16, 2012 publication of the final rule, depending on the construction date and/or nature of
the unit. We continue to evaluate the EPA's final rule, as it may require changes to our operations, including the installation of
new emissions control equipment. Furthermore, with respect to our operations that occur on federally managed public lands, on
May 16, 2013, the United States Department of the Interior ("DOI") issued a revised proposed rule that seeks to require
companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process;
(ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised
proposed rule is presently subject to an extended 90-day public comment period, which ends on August 23, 2013. DOI is
expected to issue a final rule in 2014. Under current federal law, there is no requirement for operators to disclose the use of
such chemicals, although we have already commenced similar disclosure with state regulators. In addition, legislation is
pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic
fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on October 20, 2011, the EPA
announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process.
Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as
"produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may
deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of
wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal
wells or transported to public or private treatment facilities for treatment, or recycled. The EPA asserts that due to some
contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before
introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat
wastewater before transferring it to treatment facilities. A proposed rule is expected in April 2014.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing
in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For
example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic
fracturing process, as well as the volume of water used, must be disclosed to the Railroad Commission of Texas (“RRC”) and
the public beginning February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the “well integrity rule,” which updates
the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and
reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after
cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable
groundwater. The “well integrity rule” takes effect in January 2014. In addition to state law, local land use restrictions, such as
city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.
Studies have been commissioned to determine if the use of water disposal wells increases the likelihood, frequency
and/or severity of seismic activity. Water disposal wells are used to store the water produced during the drilling and production
activities of our wells.
If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted or laws or
regulations are adopted to restrict water disposal wells, such laws could make it more difficult or costly for us to drill and
produce from conventional or tight formations as well as make it easier for third parties opposing the oil and natural gas
industry to initiate legal proceedings. In addition, if these matters are regulated at the federal level, fracturing and disposal
activities could become subject to additional permitting and financial assurance requirements, more stringent construction
specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and
also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations,
could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have
a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the
potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing or water disposal
wells are enacted into law.
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If we are unable to drill new allocation wells it could have a material adverse impact on our future production results.
In the State of Texas, “allocation wells” allow an oil and gas producer to drill a horizontal well under two or more
leaseholds that are owned by the producer. We are active in drilling and producing allocation wells. The RRC has not provided
definitive rules on the allocation well permitting process. If the RRC denies or significantly delays the permitting of allocation
wells, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn
could have a material adverse impact on our anticipated future production.
Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative
revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses
or impairment of oil and natural gas assets.
The reserve data included in this Annual Report represent estimates. Reserves estimation is a subjective process of
evaluating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Reserves that are
"proved reserves" are those estimated quantities of oil and natural gas that geological and engineering data demonstrate with
reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions
and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably
certain will commence within a reasonable time.
The estimation process relies on interpretations of available geological, geophysical, engineering and production data.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of
production and timing of developmental expenditures, including many factors beyond the control of the producer. In addition,
the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain
assumptions about future production levels, prices and costs that may not prove to be correct. Further, initial production rates
reported by us or other operators may not be indicative of future or long-term production rates. A production decline may be
rapid and irregular when compared to a well's initial production.
Quantities of proved reserves are estimated based on economic conditions in existence during the period of
assessment. Changes to oil and natural gas prices in the markets for such commodities may have the impact of shortening the
economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which
reduces proved property reserves estimates. Negative revisions of 11,944 MBOE were due to the combined effect of removing
174 proved locations and the net effect of redetermining 501 undeveloped locations. The 174 locations that were removed were
comprised of vertical Wolfberry and short horizontal laterals. They were replaced with longer horizontal laterals to better align
with future drilling plans
Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on
the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as
revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties,
which would result in a non-cash charge to earnings. See Note P.4 in our audited consolidated financial statements included
elsewhere in this Annual Report.
The potential drilling locations for our future wells that we have tentatively identified are scheduled out over many years,
making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in
certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not
be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our identified
potential drilling locations.
Although our management team has scheduled certain potential drilling locations as an estimation of our future multi-
year drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of
uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the
availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling and longer
laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other
factors. Because of these uncertain factors, we do not know if the numerous potential drilling locations we have currently
identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling
locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some
of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may
materially differ from those presently anticipated.
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Our producing properties are in a concentrated geographic area, making us vulnerable to risks associated with operating in
one major geographic area.
Our producing properties are geographically concentrated in the Permian Basin. At December 31, 2013, substantially all
of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may
be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from
wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water
shortages or other drought-related conditions or interruption of the processing or transportation of oil or natural gas.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the
areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and
lease stipulations designed to protect various wildlife. This limits our ability to operate in those areas and can later intensify
competition during certain months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may
lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially
increase our operating and capital costs. In addition, the Permian Basin has recently experienced severe winter weather and, as
a consequence, our operating results during similar periods may ultimately be adversely affected.
If commodity prices decrease, we may be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment.
Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment
reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be
required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may
incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods
in which such charges are taken. See Note B.8 to our audited consolidated financial statements included elsewhere in this
Annual Report for additional information.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not
control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of
transportation facilities owned by third parties. We do not control many of the trucks and other third-party transportation
facilities necessary for the transportation of our product and our access to them may be limited or denied. Insufficient
production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the
availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to
deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the
future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter
production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an
inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and
adversely affect our financial condition and results of operations.
Our oil and natural gas is sold to a limited number of geographic markets so an oversupply in any of those areas could have
a material negative effect on the price we receive.
Our oil and natural gas is sold to a limited number of geographic markets which each have a fixed amount of storage
and processing capacity. As a result, if such markets become oversupplied with oil and/or natural gas it could have a material
negative effect on the price we receive for our products and therefore an adverse effect on our financial condition. The current
United States restrictions on the export of oil and natural gas increase the possibility of an oversupply in any of the markets into
which we sell our products.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect
our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration, development and
exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those
reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flow and results of
operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically
finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient
additional reserves to replace our current and future production. If we are unable to replace our current and future production,
the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely
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affected.
Currently, we receive incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future
hedges at effective prices consistent with those we have received to date and oil and natural gas prices do not improve, our
cash flows and financial condition may be adversely impacted.
To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, as of December 31,
2013, we have entered into hedge contracts for 14.5 million Bbls of our projected crude oil production and 17.8 million
MMBtu of our projected natural gas production for settlement between January 2014 and December 2016. If we are unable to
enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial
condition and results of operations could be materially adversely affected. For additional information regarding our hedging
activities, please see "Item 7. Management's discussion and analysis of financial condition and results of operations—Results of
operations—Commodity derivatives."
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural
gas, we enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars,
puts and basis swaps. In accordance with applicable accounting principles, we are required to record our derivatives at fair
market value, and they are included on our consolidated balance sheet as assets or liabilities and in our consolidated statement
of operation gain (loss) on derivatives. Losses on derivatives are included in our cash flows from operating activities.
Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative
instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
the counter-party to the derivative instrument defaults on its contractual obligations;
there is an increase in the differential between the underlying price in the derivative instrument and actual prices
received; or
there are issues with regard to legal enforceability of such instruments.
In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and
natural gas, which could also have a material adverse effect on our financial condition.
The inability of our significant customers to meet their obligations to us may materially adversely affect our financial
results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit
risk is through net joint operations receivables ($16.6 million as of December 31, 2013) and the sale of our oil and natural gas
production ($57.6 million in receivables as of December 31, 2013), which we market to energy marketing companies, refineries
and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These
entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable
to control which co-owners participate in our wells. We are also subject to credit risk due to the concentration of our oil and
natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for 28.3%
of our total oil and natural gas revenues for the year ended December 31, 2013. We do not require our customers to post
collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or
their insolvency or liquidation may materially adversely affect our financial results.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we
may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could
materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and
production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas,
including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other
pollution into the environment, including groundwater and shoreline contamination;
abnormally pressured formations;
• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires, explosions and ruptures of pipelines;
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personal injuries and death;
natural disasters; and
terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a
result of:
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injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage and associated clean-up responsibilities;
regulatory investigations, penalties or other sanctions;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is
not fully covered by insurance could have a material adverse effect on our business, financial condition and results of
operations.
Locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Locations that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely
affect our results of operations and financial condition. In this Annual Report, we describe some of our current drilling
locations and our plans to explore those drilling locations. Our drilling locations are in various stages of evaluation, ranging
from those that are ready to drill to those that will require substantial additional seismic data processing and interpretation
before a decision can be made to proceed with the drilling of such locations. There is no way to predict in advance of drilling
and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields
in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present,
whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from
available data from other wells, more fully explored locations or producing fields will result in successfully locating oil or
natural gas in commercial quantities on our prospective acreage.
Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and
natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to
assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know
whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We employ 3D seismic
technology with respect to certain of our projects. The implementation and practical use of 3D seismic technology is relatively
unproven, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3D seismic
and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could
incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns.
As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling
success rate for activities in a particular area could decline.
We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an
area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring
seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If
we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze
3D data without having an opportunity to attempt to benefit from those expenditures.
Market conditions, the unavailability of satisfactory oil and natural gas gathering, processing or transportation
arrangements or operational impediments may adversely affect our access to oil, natural gas and natural gas liquids
markets or delay our production.
The availability of a ready market for our oil and natural gas production depends on a number of factors, including the
demand for and supply of oil and natural gas and the proximity of reserves to pipelines, trucking and terminal facilities. Our
ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines,
trucking and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms
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could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability
of oil and natural gas pipeline, trucking, gathering system or processing capacity. In addition, if oil or natural gas quality
specifications for the third-party oil or natural gas pipelines with which we connect change so as to restrict our ability to
transport oil or natural gas, our access to oil and natural gas markets could be impeded. If our production becomes shut in for
any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to
deliver the products to market.
Our operations are substantially dependent on the availability, use and disposal of water. Restrictions on our ability to obtain
or dispose of water may have an adverse effect on our operations, cash flow and financial condition.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able
to purchase water from local land owners and other sources for use in our operations. During the past several years, Texas has
experienced the lowest inflows of water in recent history. As a result of this severe drought, some local water districts may begin
restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water
supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce
oil and natural gas, which could have an adverse effect on our results of operations, cash flows and financial condition.
Additionally, our drilling procedures produce large volumes of water that we must properly dispose. If we are unable,
due to government regulations or otherwise, to dispose of our water or face increased costs and procedures for disposal, it could
have an adverse effect on our results of operations, cash flows and financial condition.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or
feasibility of conducting our operations or expose us to significant liabilities.
Our oil and natural gas exploration, production and gathering operations are subject to complex and stringent laws and
regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain
numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur
substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance
may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to
our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.
Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and
enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results
of operations.
See "Item 1. Business—Regulation of the oil and natural gas industry" for a further description of the laws and
regulations that affect us.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety
requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and
safety requirements applicable to our exploration, development and production activities. These laws and regulations may
require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or
other environmental impacts associated with drilling, production and transporting product pipelines or other operations;
regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling
activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require
remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen
pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws
and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change
frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and
liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution
controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain
operations.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to
remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste
generated by our operations regardless of whether such contamination resulted from the conduct of others or from
consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In
addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and
safety impacts of our operations. In addition, accidental spills or releases from our operations could expose us to significant
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liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically
in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil
and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.
To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly
operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of
operations could be materially adversely affected.
See "Item 1. Business—Regulation of environmental and occupational health and safety matters" for a further
description of the laws and regulations that affect us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services as well as fees
for the cancellation of such services could adversely affect our ability to execute our exploration and development plans
within our budget and on a timely basis.
The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations,
geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often
in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and
workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being
drilled. In particular, the high level of drilling activity in the Permian Basin has resulted in equipment shortages in those areas.
We committed to several short-term drilling contracts with various third parties in order to complete various drilling projects.
An early termination clause in these contracts requires us to pay significant penalties to the third party should we cease drilling
efforts. These penalties could significantly impact our financial statements upon contract termination. As a result of these
commitments, $1.6 million in stacked rig fees were incurred in 2009. We cannot predict whether these conditions will exist in
the future and, if so, what their timing and duration will be. The shortages as well as rig related fees could result in delays or
cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse
effect on our business, financial condition or results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to
decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938 (the "NGA") exempts natural gas gathering facilities from regulation by
the Federal Energy Regulatory Commission ("FERC"). We believe that the natural gas pipelines in our gathering systems meet
the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from
the FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally
unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the
subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future
determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase
and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted
regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily
scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be
considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to
civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in
increased operating costs and reduced demand for the oil and natural gas we produce.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse
gases" ("GHGs"), including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and other
climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions of
GHGs. One bill approved by the House of Representatives in June 2009, known as the American Clean Energy and Security
Act of 2009, would have required an 80% reduction in emissions of GHGs and almost one-half of the states have already taken
legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional
GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of
emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire
and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available
for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission
allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted
renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel
sources.
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In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs
present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA,
contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to
proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions
of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding
possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in
January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the
"tailoring rule") in May 2010, and it became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court
granted review of certain issues related to the EPA's authority to regulate such emissions from stationary sources. Oral
arguments on the issues before the Supreme Court were heard on February 24, 2014 and a decision is expected by July 2014. In
September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission
sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011
for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to
include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires
reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring
in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed
GHG rule that, if finalized, would set NSPS for new coal-fired and natural-gas fired power plants.
The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased
operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply
with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or
refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.
Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business,
financial condition and results of operations.
The derivatives reform legislation adopted by the U.S. Congress could have a negative impact on our ability to hedge risks
associated with our business.
In 2010, Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act (the “Dodd Frank Act”),
which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that
participate in that market. The Dodd Frank Act mandates that the Commodity Futures Trading Commission (“CFTC”) adopt
rules and regulations implementing the Dodd Frank Act and further define certain terms used in the Dodd Frank Act. The Dodd
Frank Act also requires the CFTC and the banking regulators to establish margin requirements for uncleared swaps. Although
there is an exception from swap clearing and trade execution requirements for commercial end users that meet certain
conditions (the “End User Exception”), certain market participants, including most if not all of our counterparties, will also be
required to clear many of their swap transactions with entities that do not satisfy the End User Exception and will have to
transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a
bilateral basis. These requirements may increase the cost to our counterparties of hedging the swap positions they enter into
with us, and thus may increase the cost to us of entering into our hedges. The changes in the regulation of swaps may result in
certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been
promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and the ultimate effect of the
adopted rules and regulations and any future rules and regulations on our business remains uncertain.
A rule adopted under the Dodd Frank Act imposing position limits in respect of transactions involving certain
commodities, including oil and natural gas, was vacated and remanded to the CFTC for further proceedings by order of the
United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The
CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the
CFTC proposed a new position limits rule which would limit trading in NYMEX contracts for Henry Hub Natural Gas, Light
Sweet Crude Oil, New York Harbor Ultra Low Sulfur No. 2 Diesel and Reformulated Blendstock for Oxygen Blending
Gasoline and other futures and swap contracts that are economically equivalent to such NYMEX contracts. Comments on the
proposed rule were due on February 10, 2014. We cannot predict whether or when the proposed rule will be adopted or the
effect of the proposed rule on our business. The Dodd Frank Act, the rules already promulgated thereunder and the proposed
rule, if adopted, could significantly increase the cost of derivative contracts (including through requirements to post collateral
which could adversely affect our available liquidity), reduce the availability of derivatives to protect against risks we encounter,
reduce our ability to monetize or restructure our existing derivative contracts, and increase our potential exposure to less
creditworthy counterparties. In addition, the Dodd Frank Act was intended, in part, to reduce the volatility of oil and natural gas
prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural
gas. Our revenues could therefore be adversely affected if a consequence of the Dodd Frank Act and regulations is to lower
commodity prices. If we reduce our use of derivatives or commodity prices decline as a result of the Dodd Frank Act and
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regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could
adversely affect our ability to plan for and fund capital expenditures and our results of operations. Any of these consequences
could have a material and adverse effect on our business, financial condition and results of operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil
and natural gas and secure trained personnel.
Our ability to acquire additional locations and to find and develop reserves in the future will depend on our ability to
evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring
properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital
available for investment in the oil and natural gas industry, especially in our focus areas. Many of our competitors possess and
employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more
for productive oil and natural gas properties and exploratory locations and to evaluate, bid for and purchase a greater number of
properties and locations than our financial or personnel resources permit. In addition, other companies may be able to offer
better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain
qualified personnel has increased due to competition and may increase substantially in the future. We may not be able to
compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry affect the demand for certain types of equipment. During
2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are
able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling"
in recent years whereby a series of horizontal wells are drilled in succession by walking or skidding a drilling rig at a single-site
location. As a result, the demand for rigs capable of carrying out pad drilling techniques has increased. If we are unable to
secure such rigs in a timely or cost-efficient manner it could have a material adverse effect on our business.
The loss of senior management or technical personnel could materially adversely affect operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior
management or technical personnel, including Randy A. Foutch, our Chairman and Chief Executive Officer, could have a
material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of
these individuals.
A significant reduction by Warburg Pincus of its ownership interest in us could adversely affect us.
Warburg Pincus is our largest stockholder and two members of our board of directors are affiliates of Warburg Pincus.
As of December 31, 2013, Warburg Pincus owned 49.1% of our outstanding common stock. We believe that Warburg Pincus'
substantial ownership interest in us provides them with an economic incentive to assist us to be successful. However, Warburg
Pincus is not obligated to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or
otherwise reduce its ownership interest in us. If Warburg Pincus sells all or a substantial portion of its ownership interest in us,
Warburg Pincus may have less incentive to assist in our success and its affiliates that are members of our board of directors
may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could
adversely affect our cash flows or results of operations.
We have limited control over activities on properties we do not operate, which could materially reduce our production and
revenues.
A portion of our business activities is conducted through joint operating agreements under which we own partial
interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have
control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an
operator of our wells to adequately perform operations or an operator's breach of the applicable agreements could materially
reduce our production and revenues. The success and timing of our drilling and development activities on properties operated
by others, therefore, depends upon a number of factors outside of our control, including the operator's timing and amount of
capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.
Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the
operator in the event of poor performance.
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We are involved as a passive minority-interest partner in joint ventures and are subject to risks associated with joint venture
partnerships.
We are involved as a passive minority-interest partner in joint venture relationships and may initiate future joint
venture projects. Entering into a joint venture as a passive minority-interest partner involves certain risks which include: the
need to contribute funds to the joint venture to support its operating and capital needs; the inability to exercise voting control
over the joint venture; economic or business interests which are not aligned with our venture partners, including the holding
period and timing of ultimate sale of the ventures' underlying assets; and the inability for the venture partner to fulfill its
commitments and obligations due to financial or other difficulties.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital,
increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit
our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive
disadvantage. For example, as of February 26, 2014 we have $812.5 million of borrowing capacity on our Senior Secured
Credit Facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed
borrowing of the full $812.5 million available on our Senior Secured Credit Facility would result in increased annual interest
expense of $8.1 million and a decrease in our net income before income taxes. Recent and continuing disruptions and volatility
in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations.
We require continued access to capital. A significant reduction in our cash flows from operations or the availability of credit
could materially and adversely affect our ability to achieve our planned growth and operating results.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
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•
•
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recoverable reserves;
future oil and natural gas prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. Our assessment will not reveal all existing or potential
problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily
observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to
provide effective contractual protection against all or part of the problems. We often are not entitled to contractual
indemnification for environmental liabilities and acquire properties on an "as is" basis. Even in those circumstances in which
we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill
its contractual obligations. Problems with properties we acquire could have a material adverse effect on our business, financial
condition and results of operations.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so
may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of businesses that complement or expand our current business. We may not be
able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be
able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into
our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a
disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and
for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able
to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on
acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the
acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties
could have a material adverse effect on our financial condition and results of operations.
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We have incurred losses from operations for various periods since our inception and may do so in the future.
We incurred net losses from our inception to December 31, 2006 of $1.8 million and for each of the years ended
December 31, 2007, 2008 and 2009 of $6.1 million, $192.0 million and $184.5 million, respectively. Our financial statements
include deferred tax assets, which require management's judgment when evaluating whether they will be realized. Our
development of and participation in an increasingly larger number of locations has required and will continue to require
substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to
economically find, develop, exploit and acquire oil and natural gas reserves and realize our deferred tax assets. As a result, we
may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical accounting policies and
estimates."
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties
in the energy industry. As of December 31, 2013, the Company had two customers accounting for 36.0% and approximately
15.7% of oil and natural gas sales accounts receivable. As of December 31, 2013, we had four customers whose joint
operations accounts receivable accounted for 16.0%, 14.1%, 13.1% and 10.9% of our total joint operations accounts receivable.
This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements
expose us to credit risk in the event of nonperformance by counterparties. Current economic circumstances may further
increase these risks.
We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors
beyond our control.
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends
on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive,
legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash
flow from operations or that future funding will be available to us under our Senior Secured Credit Facility, equity offerings or
other actions in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to
refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any
of our indebtedness on commercially reasonable terms or at all.
We may incur significant additional amounts of debt.
As of February 26, 2014, we had total long-term indebtedness of $1.5 billion. In addition, we may be able to incur
substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of
additional indebtedness contained in the indentures governing our senior unsecured notes and in our Senior Secured Credit
Facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of
indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our
existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial
obligations. In addition, the restrictions on the incurrence of additional indebtedness contained in the indentures governing the
senior unsecured notes apply only to debt that constitutes indebtedness under the indentures.
Our debt agreements contain restrictions that will limit our flexibility in operating our business.
Our Senior Secured Credit Facility and the indentures governing our senior unsecured notes each contain, and any
future indebtedness we incur may contain, various covenants that limit our ability to engage in specified types of transactions.
These covenants limit our ability to, among other things:
•
•
incur additional indebtedness;
pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted
payments;
• make certain investments;
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•
•
sell certain assets;
create liens;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and
enter into certain transactions with our affiliates.
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As a result of these covenants, we are limited in the manner in which we may conduct our business and we may be
unable to engage in favorable business activities or finance future operations or our capital needs. In addition, the covenants in
our Senior Secured Credit Facility require us to maintain a minimum working capital ratio and minimum interest coverage ratio
and also limit our capital expenditures. A breach of any of these covenants could result in a default under one or more of these
agreements, including as a result of cross default provisions and, in the case of our Senior Secured Credit Facility, permit the
lenders to cease making loans to us. Upon the occurrence of an event of default under our Senior Secured Credit Facility, the
lenders could elect to declare all amounts outstanding under our Senior Secured Credit Facility to be immediately due and
payable and terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under
our other indebtedness, including the senior unsecured notes. If we were unable to repay those amounts, the lenders under our
Senior Secured Credit Facility could proceed against the collateral granted to them to secure that indebtedness. We pledged a
significant portion of our assets as collateral under our Senior Secured Credit Facility. If the lenders under our Senior Secured
Credit Facility accelerate the repayment of the borrowings thereunder, the proceeds from the sale or foreclosure upon such
assets will first be used to repay debt under our Senior Secured Credit Facility, and we may not have sufficient assets to repay
our unsecured indebtedness thereafter.
We have substantial cash balances that we invest in what we believe to be relatively short-term, highly-liquid and high credit
quality investments. In addition, our management has broad discretion as to the use of our cash and might invest or spend
our cash in ways that may not yield a return. This could result in a material adverse effect on our results of operations,
liquidity or financial condition.
We have substantial cash balances that we maintain for working capital and general corporate purposes, which may
include acquisitions. Our management has considerable discretion in the use of our cash, and might not be able to use our cash
for purposes that increase our operating results or market value. Until the cash is used, it may from time to time be invested in
what we believe to be relatively short-term, highly-liquid and high credit quality investments. We intend the investment risks,
including counterparty default and lack of liquidity, on these types of investments to be relatively low, but market rates of
return on these types of investments are also generally relatively low. Our efforts to manage the investment risks could be
unsuccessful and this could result in a material adverse effect on our results of operations, liquidity or financial condition.
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions
currently available with respect to oil and natural gas exploration and development are eliminated as a result of future
legislation.
Legislation has been proposed that would, if enacted, eliminate certain key U.S. federal income tax preferences
currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to
(i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions
for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and
(iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of
the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any
legislation as a result of these proposals or any other similar change in U.S. federal income tax law could eliminate or postpone
certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such
change could materially adversely affect our financial condition and results of operations by increasing the costs we incur
which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in
lower revenues and decreases in production and reserves.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations
information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or
create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or
attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and
natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized
business activities. Any such consequence could have a material adverse effect on our business.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain
unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees,
threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and
pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to,
malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to
disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.
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Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to
such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from
materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical
infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation,
financial position, results of operations or cash flows.
Risks relating to our common stock
Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware state law contain
provisions that may have the effect of delaying or preventing a change in control and may adversely affect the market price
of our capital stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock
without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the
rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter
or prevent a change in control and could adversely affect the voting power or economic value of our shares.
In addition, some provisions of our amended and restated certificate of incorporation and amended and restated
bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial
to our stockholders, including:
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•
•
•
•
limitations on the ability of our stockholders to call special meetings;
a separate vote of 75% of the voting power of the outstanding shares of capital stock in order for stockholders to
amend the bylaws in certain circumstances;
our board of directors is divided into three classes with each class serving staggered three-year terms;
stockholders do not have the right to take any action by written consent; and
advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be
acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning
generally that a stockholder who owns 15% of our stock cannot acquire us for a period of three years from the date such
stockholder became an interested stockholder, unless various conditions are met, such as the approval of the transaction by our
board of directors. Warburg Pincus, however, is not subject to this restriction.
The concentration of our capital stock ownership among our largest stockholder will limit your ability to influence
corporate matters.
As of December 31, 2013, Warburg Pincus owned 49.1% of our outstanding common stock. Consequently, Warburg
Pincus has significant influence over all matters that require approval by our stockholders, including the election of directors
and approval of significant corporate transactions. This concentration of ownership limits the ability of other stockholders to
influence corporate matters.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its
affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business
activities or business opportunities. Warburg Pincus LLC is a private equity firm that has invested in, among other things,
companies in the energy industry. As a result, Warburg Pincus' existing and future portfolio companies which it controls may
compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
We have also renounced our interest in certain business opportunities. Our amended and restated certificate of
incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any
business opportunity, transaction or other matter in which Warburg Pincus or any private fund that it manages or advises, any of
their respective officers, directors, partners and employees, and any portfolio company in which such persons or entities have
an equity interest (other than us and our subsidiaries) (each, a "specified party") participates or desires or seeks to participate
and that involves any aspect of the energy business or industry, even if the opportunity is one that we might reasonably have
pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such specified party shall be liable to
us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact
that such specified party pursues or acquires any such business opportunity, directs any such business opportunity to another
person or fails to present any such business opportunity, or information regarding any such business opportunity, to us.
Notwithstanding the foregoing, we do not renounce any interest or expectancy in any business opportunity, transaction or other
matter that is offered in writing solely to (i) one of our directors or officers who is not also a specified party or (ii) a specified
party who is one of our directors, officers or employees and is offered such business opportunity solely in his or her capacity as
43
our director, officer or employee. By renouncing our interest and expectancy in any business opportunity that from time to time
may be presented to Warburg Pincus and its affiliates, our business and prospects could be adversely affected if attractive
business opportunities are procured by such parties for their own benefit rather than for ours.
Because we have no plans to pay, and are currently restricted from paying dividends on our common stock, investors must
look solely to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to
retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the
discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other
considerations that our board of directors deems relevant. Covenants contained in our Senior Secured Credit Facility and the
indentures governing our senior unsecured notes restrict the payment of dividends. Investors must rely on sales of their
common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Investors seeking cash dividends should not purchase our common stock.
The availability of shares for sale in the future could reduce the market price of our common stock.
In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies
by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into,
or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership
interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.
44
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
Item 3. Legal Proceedings
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including
proceedings for which we have insurance coverage. As of the date hereof, we are not party to any legal proceedings which we
currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.
Item 4. Mine Safety Disclosures
Not applicable.
45
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Registrant's Common Equity. Our common stock is listed on the New York Stock Exchange ("NYSE")
under the symbol "LPI." The following table sets forth the range of high and low sales prices of our common stock as reported
by the NYSE:
2013:
Fourth Quarter ...............................................................................................................................
Third Quarter .................................................................................................................................
Second Quarter ..............................................................................................................................
First Quarter...................................................................................................................................
2012:
Fourth Quarter ...............................................................................................................................
Third Quarter .................................................................................................................................
Second Quarter ..............................................................................................................................
First Quarter...................................................................................................................................
Price per share
High
Low
$
$
$
$
$
$
$
$
33.52
30.00
20.85
20.03
22.37
24.09
26.63
26.80
$
$
$
$
$
$
$
$
25.30
20.21
15.95
16.56
17.11
21.10
18.79
20.84
On February 26, 2014, the last sale price of our common stock, as reported on the NYSE, was $27.43 per share.
Holders. As of February 24, 2014, there were 59 holders of record of our common stock.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our senior secured
credit facility and the indentures governing our senior unsecured notes restrict the payment of cash dividends on our common
stock. See "Item 1A. Risk Factors—Risks related to our business—Our debt agreements contain restrictions that will limit our
flexibility in operating our business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations—Cash flows—Debt." We currently intend to retain all future earnings for the development and growth of our
business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable
future.
Repurchase of Equity Securities.
Period
October 1, 2013 - October 31, 2013 ................
November 1, 2013 - November 30, 2013 ........
December 1, 2013 - December 31, 2013 .........
______________________________________________________________________________
Total number of
shares withheld(1)
1,911
8,317
11,618
$
$
$
Average price
per share
32.42
28.91
26.24
Total number of
shares purchased as
part of publicly
announced plans
Maximum number of
shares that may yet be
purchased under the
plan
—
—
—
—
—
—
(1) Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse
of restrictions on restricted stock.
Unregistered Sales of Equity Securities and Use of Proceeds. None.
46
Stock Performance Graph. The following performance graph and related information shall not be deemed "soliciting
material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the
Securities Act or Exchange Act, except to the extent that we specifically request that such information be treated as "soliciting
material" or specifically incorporate such information by reference into such a filing.
The performance graph below shows the cumulative total return to our common stockholders from December 15,
2011, the date on which our common stock began trading on the NYSE, through December 31, 2013, as compared to the
returns on the Standard and Poor's 500 Index ("S&P 500") and the Standard and Poor's 500 Oil & Gas Exploration &
Production Index ("S&P O&G E&P"). The comparison was prepared based upon the following assumptions:
1. $100 was invested in our common stock at its initial public offering price of $17 per share and invested in the
S&P 500 and the S&P O&G E&P on December 15, 2011 at the closing price on such date; and
2. Dividends, if any, are reinvested.
47
Item 6. Selected Historical Financial Data
The selected historical consolidated financial data presented below is not intended to replace our audited consolidated
financial statements. You should read the following data along with "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the consolidated financial statements and related notes, each of which is
included elsewhere in this Annual Report. We believe that the assumptions underlying the preparation of our financial
statements are reasonable. The financial information included in this Annual Report may not be indicative of our future results
of operations, financial position and cash flows.
Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial
data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 are
derived from our audited consolidated financial statements and the notes thereto included elsewhere in this Annual Report. The
historical financial data for the years ended December 31, 2010 and 2009 and the balance sheet data as of December 31, 2011,
2010 and 2009 are derived from our audited financial statements not included in this Annual Report.
(in thousands, except per share data)
Statement of operations data(2):
Total revenues...........................................................................
Total costs and expenses...........................................................
Operating income (loss) ...........................................................
.....................................................
Income (loss) from continuing operations before income
taxes..........................................................................................
Income tax (expense) benefit ...................................................
Income (loss) from continuing operations ...............................
Income (loss) from discontinued operations, net of tax ...........
Net income (loss) .....................................................................
Net income per common share:
For the years ended December 31,
2013(1)
2012
2011
2010
2009
$ 665,257
450,906
$ 583,894
411,954
$ 506,347
303,827
$ 239,791
164,230
214,351
(23,267)
171,940
(77,176)
202,520
(36,932)
75,561
(12,516)
$ 94,347
345,613
(251,266)
(4,888)
191,084
(74,507)
116,577
1,423
$ 118,000
94,764
(33,003)
61,761
(107)
$ 61,654
165,588
(59,612)
105,976
(422)
$ 105,554
63,045
24,847
87,892
(1,644)
$ 86,248
(256,154)
73,181
(182,973)
(1,522)
$(184,495)
Basic:
Income from continuing operations .........................................
Income (loss) from discontinued operations ............................
Net income per share................................................................
Diluted:
Income from continuing operations .........................................
Income (loss) from discontinued operations ............................
Net income per share................................................................
$
$
$
$
0.88
0.01
0.89
0.87
0.01
0.88
$
$
$
$
0.49
—
0.49
0.48
—
0.48
$
$
$
$
0.99
(0.01)
0.98
0.98
—
0.98
_______________________________________________________________________________
(1) See Note C to our audited consolidated financial statements included elsewhere in this Annual Report for additional
information regarding our Anadarko Basin Sale.
(2) The oil and natural gas properties that were a component of the Anadarko Basin Sale are not presented as held for sale
nor are their results of operations presented as discontinued operations for the historical periods presented pursuant to
the rules governing full cost accounting for oil and gas properties. The results of operations of the associated pipeline
assets and various other associated property and equipment are presented as results of discontinued operations, net of
tax.
48
(in thousands)
Balance sheet data:
2013
2012
2011
2010
2009
As of December 31,
Cash and cash equivalents .......................................
Net property and equipment.....................................
Total assets...............................................................
Current liabilities .....................................................
Long-term debt.........................................................
Stockholders' equity.................................................
$
198,153
$
33,224
$
28,002
$
31,235
$
14,987
2,204,324
2,113,891
1,378,509
809,893
2,623,760
2,338,304
1,627,652
1,068,160
253,969
262,068
1,051,538
1,216,760
1,272,256
831,723
214,361
636,961
760,013
150,243
491,600
411,099
396,100
625,344
79,265
247,100
289,107
(in thousands)
Other financial data:
For the years ended December 31,
2013
2012
2011
2010
2009
Net cash provided by operating activities................
Net cash used in investing activities(1)
.....................
Net cash provided by financing activities................
$
$
364,729
(329,884)
130,084
376,776
(940,751)
569,197
$
$
344,076
(706,787)
359,478
$
157,043
(460,547)
319,752
112,669
(361,333)
250,139
_______________________________________________________________________________
(1) Net cash used in investing activities for the year ended December 31, 2013 is offset by proceeds received for the
Anadarko Basin Sale. See Note C to our audited consolidated financial statements included elsewhere in this Annual
Report for additional information.
For the years ended December 31,
(in thousands, unaudited)
Adjusted EBITDA(1)...................................................
_______________________________________________________________________________
472,166
2013
2012
$
$
443,434
2011
2010
2009
$
384,342
$
188,568
$
97,823
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of
Adjusted EBITDA to net income (loss) see "—Non-GAAP financial measures and reconciliations" below.
Non-GAAP financial measures and reconciliations
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest
expense, depletion, depreciation and amortization, impairment of long-lived assets, write-off of deferred loan costs, bad debt
expense, gains or losses on disposal of assets, total gains or losses on derivatives, cash settlements of matured commodity
derivatives, cash settlements on early terminated derivatives, premiums paid for derivatives that matured during the period,
non-cash stock-based compensation and income tax expense or benefit. 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 and 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, 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, 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
49
reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance
under our debt agreements differ.
The following presents a reconciliation of net income (loss) for continuing and discontinued operations to Adjusted
EBITDA:
(in thousands, unaudited)
2013
2012
2011
2010
2009
For the years ended December 31,
Net income (loss) .................................................................
Plus:
Interest expense..................................................................
Depletion, depreciation and amortization ..........................
Impairment of long-lived assets.........................................
Write-off of deferred loan costs.........................................
Bad debt expense ...............................................................
Loss on disposal of assets, net ...........................................
Gain on derivatives, net .....................................................
Cash settlements received for matured commodity
derivatives, net ...................................................................
Cash settlements received for early terminations and
modifications of derivatives, net........................................
Premiums paid for derivatives that matured during the
period(1) ..............................................................................
Non-cash stock-based compensation .................................
Income tax expense (benefit) .............................................
Adjusted EBITDA ...........................................................
$ 118,000
$
61,654
$ 105,554
$
86,248
$ (184,495)
100,327
234,571
85,572
243,649
50,580
176,366
18,482
97,411
—
1,502
653
—
—
—
243
6,195
—
—
—
—
7,464
58,005
246,669
—
—
1,508
(79,878)
52
(8,388)
40
(19,736)
30
(5,815)
85
(2,350)
4,046
27,025
3,719
22,701
52,117
6,008
—
—
—
—
(11,292)
21,433
75,288
(9,135)
10,056
32,949
(4,104)
6,111
59,374
$ 472,166
$ 443,434
$ 384,342
(5,934)
1,257
(25,812)
$ 188,568
$
(7,085)
1,419
(74,006)
97,823
______________________________________________________________________________
(1) Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective
periods presented.
50
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in
conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report. The
following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected
performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often
do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to
vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures,
availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, potential failure to
achieve production from development projects, operational factors affecting the commencement or maintenance of producing
wells, the condition of the capital and financial markets generally, as well as our ability to access them, the proximity to and
capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or
regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report,
all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur. See "Cautionary Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors."
Executive overview
We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas
properties primarily in the Permian Basin in West Texas. On August 1, 2013, we sold our properties in the Anadarko Granite
Wash, Eastern Anadarko and Central Texas Panhandle (the "Anadarko Basin") in the Mid-Continent region of the United States.
We have grown rapidly through our drilling program and by making strategic acquisitions and joint ventures. In
December 2011, we completed the Corporate Reorganization and IPO and in December 2013, we completed the Internal
Consolidation. See Note A to our consolidated financial statements included elsewhere in this Annual Report for definitions of
and additional information regarding the Corporate Reorganization, the IPO and the Internal Consolidation.
Our financial and operating performance for the year ended December 31, 2013 included the following:
• Oil and natural gas sales of $664.8 million, compared to $583.6 million for the year ended December 31, 2012;
• Average daily production of 30,716 BOE/D, compared to 30,874 BOE/D for the year ended December 31, 2012;
• Estimated net proved reserves of 203,615 MBOE as of December 31, 2013, compared to 188,632 MBOE as of
December 31, 2012; and
• Adjusted EBITDA (a non-GAAP financial measure) of $472.2 million, compared to $443.4 million for the year
ended December 31, 2012.
Recent Developments
Notes Offering
On January 23, 2014, we completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior
unsecured notes due 2022, and entered into an indenture among Laredo, Laredo Midstream and Wells Fargo Bank, National
Association, as trustee. The new senior unsecured notes will mature on January 15, 2022 with interest accruing at a rate of 5
5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15,
2014. The new senior unsecured notes are guaranteed on a senior unsecured basis by Laredo Midstream.
The new senior unsecured notes were issued pursuant to the indenture in a transaction exempt from the registration
requirements of the Securities Act. The new senior unsecured notes were offered and sold only to qualified institutional buyers
pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the
Securities Act. We received net proceeds of $442.2 million from the offering, after deducting the initial purchasers’ discount
and offering expenses. We plan to use the net proceeds of the offering for general working capital purposes.
In connection with the issuance of the new senior unsecured notes, Laredo and Laredo Midstream entered into a
registration rights agreement with the initial purchasers of the new senior unsecured notes and have agreed to use commercially
reasonable efforts to file a registration statement with the SEC relating to an offer to exchange the new senior unsecured notes
for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are
registered under the Securities Act so as to permit the exchange offer to be consummated within 365 days after the issuance of
the new senior unsecured notes. Under certain circumstances, Laredo and Laredo Midstream will be obligated to pay additional
interest if they fail to comply with their obligations to register the new senior unsecured notes within the specified time periods.
51
Unwinding of commodity contract
In February 2014, we unwound a physical commodity contract with a Light Louisiana Sweet Argus reference price and
the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet
Argus and the Brent International Petroleum Exchange index oil prices. We received net proceeds of $76.7 million from the
early termination of these contracts. We agreed to settle the contracts early due to our counterparty's decision to exit the
physical commodity trading business. It is not our past practice nor do we expect to settle physical contracts financially in the
future.
Mergers and acquisitions
Our use of capital for development and acquisitions allows us to direct our capital resources toward what we believe to
be the most attractive opportunities as market conditions evolve. We have historically developed properties that we believe will
meet or exceed our rate of return criteria. For acquisitions of properties with additional development and exploration potential,
we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of
capital spending. We also make acquisitions in core, mature areas where management can leverage knowledge and experience
to identify upsides in the assets.
On July 1, 2011, we consummated the acquisition of Broad Oak for consideration consisting of (i) cash payments
totaling $82.0 million to certain members of Broad Oak management and employees, (ii) equity issuances of 86.5 million
preferred Laredo Petroleum, LLC units to Warburg Pincus, (iii) equity issuances of 2.4 million preferred Laredo
Petroleum, LLC units to certain directors and management of Broad Oak and (iv) repayment of the $265.4 million of
outstanding debt under the Broad Oak credit facility. Immediately following the consummation of such transaction, Laredo
Petroleum, LLC assigned 100% of its ownership interest in Broad Oak to Laredo Petroleum, Inc. as a contribution to capital.
On July 12, 2012, we completed the acquisition of additional working interest in certain oil and natural gas properties
located in Glasscock County, Texas, for a contract price of $20.5 million from a private company, net of closing purchase price
adjustments.
On September 6, 2013, we completed the acquisition of proved and unproved oil and natural gas properties located in
Glasscock County, TX, from private parties for $36.7 million consisting of cash and 123,803 shares of our restricted common
stock, subject to customary closing adjustments.
Divestitures
On August 1, 2013, we completed the sale of oil and gas properties located in the Anadarko Basin in the State of
Oklahoma and the State of Texas, associated pipeline assets and various other related property and equipment (the "Anadarko
Basin Sale") for a purchase price of $438.0 million. The purchase price (including the buyers' deposits) consisted of $400.0
million from certain affiliates of EnerVest, Ltd. and $38.0 million from other third parties in connection with the exercise of
such third parties' preferential rights associated with certain of the oil and gas properties. Approximately $388.0 million of the
purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing
full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013,
the net proceeds were $428.3 million, net of working capital adjustments. The net proceeds were used to pay off our Senior
Secured Credit Facility and for working capital purposes.
Effective August 1, 2013, the operations and cash flows of these properties were eliminated from our ongoing
operations and we do not have continued involvement in the operation of these properties. The oil and natural gas properties,
which are a component of the assets sold, are not presented as discontinued operations pursuant to the rules governing full cost
accounting for oil and gas properties. The results of operations of the associated pipeline assets and various other associated
property and equipment have been presented as results of discontinued operations, net of tax. Accordingly we have reclassified
certain prior period amounts in the consolidated financial statements included elsewhere in this Annual Report as discontinued
operations. See Notes B.3 and C to our consolidated financial statements included elsewhere in this Annual Report for
additional discussion of these reclassifications and the Anadarko Basin Sale.
On December 20, 2013, we completed the sale of 37,000 net acres in the Dalhart Basin, including one producing well,
for $20.4 million, subject to customary closing adjustments. The net proceeds were used for working capital purposes.
52
Management and board changes
During the year ended December 31, 2013, our board of directors appointed Jay P. Still to become President and Chief
Operating Officer, effective July 8, 2013. Our board of directors also appointed Mr. Still to become a member of the board of
directors, effective July 8, 2013, and hold office until the next annual meeting of stockholders or until his successor has been
duly elected and qualified. Jerry R. Schuyler, our former President and Chief Operating Officer and formerly one of our
directors, resigned as an officer and director of Laredo effective July 8, 2013, and continued with Laredo in an advisory
capacity until he retired on November 21, 2013. In connection with Mr. Schuyler's retirement, the compensation committee of
our board of directors elected to accelerate the vesting of all of his restricted stock and restricted stock options, as well as all of
his performance unit awards (as if the performance criteria had been fully satisfied) to the date of his retirement.
John E. Minton, who had been with us since October 2007, elected to retire from his position as Senior Vice President
- Reservoir Engineering effective December 6, 2013. In connection with his retirement, the compensation committee of our
board of directors elected to accelerate the vesting of all of his restricted stock and restricted stock options, as well as all of his
performance unit awards (as if the performance criteria had been fully satisfied) to the date of his retirement.
Common stock transactions
On August 19, 2013, we, together with certain affiliates of Warburg Pincus and members of our management (together
with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of our common stock by us and
(ii) 3,000,000 shares of our common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781
per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders
sold an additional 1,577,583 shares of our common stock pursuant to the option to purchase additional shares of our common
stock granted to the associated underwriters. We intend to use the $298.1 million net proceeds from the Follow-on Offering to
implement our planned exploration and development activities, accelerate our capital program and for general working capital
purposes. We did not receive any proceeds from the sale of the shares of our common stock by the Selling Stockholders.
On September 6, 2013, we issued 123,803 restricted shares of our common stock to third parties as partial
consideration for an acquisition of proved and unproved oil and natural gas properties. See Note C to our audited consolidated
financial statements included elsewhere in the Annual Report for additional information.
During the year ended December 31, 2013, Warburg Pincus distributed our common stock pro rata to certain of the
Warburg Pincus limited partners. As of February 24, 2014, Warburg Pincus owned 49.1% of our outstanding common stock.
The following details the distributions throughout the year ended December 31, 2013:
Date of distribution
June 25, 2013 ..............................................................................
August 19, 2013..........................................................................
August 27, 2013..........................................................................
September 24, 2013 ....................................................................
November 25, 2013 ....................................................................
Derivative terminology modifications
Number of shares
distributed
Distribution % of Warburg Pincus'
holdings of our common stock prior to the
distribution
3,515,263
2,890,000
1,577,583
3,515,263
6,008,476
4%
3%
2%
4%
8%
We have modified our terminology describing gains and losses on derivatives. In our revised presentation, "Cash
settlements received for matured derivatives" describe the gain or loss from contracts that settled during the current period,
calculated as the difference between the contract price and the market settlement price of the matured derivatives. In addition,
we have revised our non-GAAP financial measure Adjusted EBITDA and our average hedged sale price calculation to include
"Premiums paid for derivatives that matured during the period" which represents current period settlements of matured
derivatives and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments
settled in the period.
Related Party
We have a gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Until May 2013,
Warburg Pincus Private Equity IX, L.P., a major stockholder of Laredo, and other affiliates of Warburg Pincus, held material
investment interests in Targa. We considered Targa a related party until May 2013, and accordingly have continued our
disclosure of our net oil and natural gas sales and our oil and natural gas sales receivable attributable to Targa throughout 2013.
As we no longer consider Targa a related party, we will discontinue this disclosure in 2014.
53
Core area of operations
The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories,
long-lived reserves, high drilling success rates and high initial production rates. As of December 31, 2013, we had assembled
202,084 net acres in the Permian Basin.
Reserves and pricing
Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves, reported on a two-stream
basis, as of December 31, 2013, 2012 and 2011. As of December 31, 2013, we had 203,615 MBOE of estimated net proved
reserves as compared to 188,632 MBOE of estimated net proved reserves as of December 31, 2012 and 156,453 MBOE of
estimated net proved reserves as of December 31, 2011.
Our results of operations are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate
widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market
uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities,
commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the
economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.
Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas
liquids in our natural gas is included in the wellhead natural gas price. The unweighted arithmetic average first-day-of-the-
month index prices for the prior 12 months were $93.52 per Bbl for oil and $3.57 per MMBtu for natural gas as of December
31, 2013, $91.21 per Bbl for oil and $2.63 per MMBtu for natural gas as of December 31, 2012 and $92.71 per Bbl for oil and
$3.99 per MMBtu for natural gas as of December 31, 2011. The prices used to estimate proved reserves for all periods did not
give effect to derivative transactions. These prices were held constant throughout the life of the properties and have been
adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting
the price received at the wellhead.
We have entered into a number of commodity derivatives, which have allowed us to offset a portion of the changes
caused by price fluctuations on our oil and natural gas production as discussed in “Item 7A. Quantitative and Qualitative
Disclosures About Market Risk.”
Sources of our revenue
Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include
the effects of derivatives. For the year ended December 31, 2013, our revenues from continuing operations are comprised of
sales of 74% oil and 26% gas. Our revenues may vary significantly from period to period as a result of changes in volumes of
production sold or changes in commodity prices.
Principal components of our cost structure
Lease operating and transportation and treating expenses. These are daily costs incurred to bring oil and natural gas
out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also
include maintenance, repairs and workover expenses related to our oil and natural gas properties.
Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of
revenues from products sold at market prices or at fixed rates established by federal, state or local taxing authorities. We take
full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate
to the changes in oil and natural gas revenues. Ad valorem taxes are property taxes based on the value of our reserves attributed
to our properties located in Texas.
Drilling and production. These are costs incurred to maintain facilities that support our drilling activities.
General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate
staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes,
audit and other fees for professional services and legal compliance.
Stock-based compensation. These are costs incurred for compensation expense related to employee and director
stock and option awards granted which have been recognized on a straight-line basis over the vesting period associated with the
award.
Accretion of asset retirement obligations. Accretion is a non-cash charge which represents changes in our asset
retirement liability due to the passage of time.
54
Depletion, depreciation and amortization. Under the full cost accounting method, we capitalize all acquisition,
exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural
gas within a cost center and then systematically expense those costs on a units of production basis based on proved oil and
natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost
of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less
accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the
estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed
assets related to our pipelines and other fixed assets utilizing the straight-line method over the useful life of the asset.
Other income (expense)
Gain (loss) on commodity derivatives. We utilize commodity derivatives to reduce our exposure to fluctuations in the
price of crude oil and natural gas. This amount represents (i) the recognition of gains and losses associated with our open
derivatives as commodity prices change and commodity derivatives expire or new ones are entered into, and (ii) our gains and
losses on the settlement of these commodity derivatives. We classify these gains and losses as operating activities in our
consolidated statements of cash flows.
Gain (loss) on interest rate derivatives. We utilized interest rate swaps and caps to reduce our exposure to
fluctuations in interest rates on our outstanding debt. This amount represents (i) the recognition of gains and losses associated
with interest rate derivatives as interest rates change and interest rate derivatives expire or new ones are entered into, and
(ii) our gains and losses on the settlement of these interest rate contracts. We classify these gains and losses as operating
activities in our consolidated statements of cash flows. During each of the years ended December 31, 2013 and 2012, we had
one interest rate swap and one interest rate cap outstanding for a total notional amount of $100.0 million with fixed pay rates
ranging from 1.11% to 3.00% until their expiration in September 2013.
Income from equity method investee. We have invested in a company where we own 49% of the ownership units. As
such, we account for this investment under the equity method of accounting with our proportionate share of net gain (loss)
reflected in the consolidated statements of operations as "Income from equity method investee" and the carrying amount
reflected in the audited consolidated balance sheet as "Investment in equity method investee." See Note M to our audited
consolidated financial statements included elsewhere in this Annual Report for additional information regarding this
investment.
Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions
with borrowings under our Senior Secured Credit Facility, our senior unsecured notes and, prior to its termination on July 1,
2011, the Broad Oak credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates
and our financing decisions. We have entered into various interest rate derivatives to mitigate the effects of interest rate
changes. We do not designate these derivatives as hedges and therefore hedge accounting treatment is not applicable. Gains or
losses on these interest rate contracts are included in non-operating income (expense) as discussed above. We reflect interest
paid to the lenders and bondholders in interest expense. In addition, we include the amortization of deferred financing costs
(including origination and amendment fees), commitment fees and annual agency fees in interest expense.
Interest and other income. This represents the interest received on our cash and cash equivalents as well as other
miscellaneous income.
Income tax expense. Income taxes in our financial statements are generally presented on a consolidated basis.
However, U.S. tax laws do not allow tax losses of Laredo Petroleum—Dallas, Inc. to offset income and losses of another entity
until after the consummation of the Broad Oak acquisition on July 1, 2011. As such, the financial accounting for the income tax
consequences of each taxable entity is calculated separately for all periods prior to July 1, 2011.
We are subject to federal and state corporate income taxes and Texas franchise tax. These taxes are accounted for
under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective
tax basis and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a change in tax laws or tax rates is recognized in income
in the period that includes the enactment date.
On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected
realization of the deferred tax assets and adjusts the amount of such allowances, if necessary. We considered all available
evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was
needed on either the federal or Oklahoma net operating loss carry-forwards. Such consideration included estimated future
projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the
55
timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2013, our ability to capitalize
intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring
unused, and future projections of Oklahoma sourced income.
Results of operations
For the year ended December 31, 2013 as compared to the year ended December 31, 2012, and for the year ended December
31, 2012 as compared to the year ended December 31, 2011
Production, revenue and pricing
The following table sets forth information regarding production and revenue and average sales prices from continuing
operations per BOE, for the periods presented:
(unaudited)
Production data:
Oil (MBbl) .............................................................................................................
Natural gas (MMcf) ...............................................................................................
Oil equivalents (MBOE)(1) .....................................................................................
Average daily production (BOE/D)(1).....................................................................
% Oil ......................................................................................................................
Revenues (in thousands):
Oil ..........................................................................................................................
Natural gas .............................................................................................................
Transportation and treating ....................................................................................
Total revenues.................................................................................................
Average sales prices:
Oil, realized ($/Bbl)(2) ............................................................................................
Natural gas, realized ($/Mcf)(2) ..............................................................................
Average price, realized ($/BOE)(2) .........................................................................
Oil, hedged ($/Bbl)(3) .............................................................................................
Natural gas, hedged ($/Mcf)(3) ...............................................................................
Average price, hedged ($/BOE)(3) ..........................................................................
_______________________________________________________________________________
For the years ended December 31,
2013
2012
2011
5,487
34,348
11,211
30,716
4,775
39,148
11,300
30,874
3,368
31,711
8,654
23,709
49%
42%
39%
$ 494,676
$ 414,932
$ 306,481
170,168
168,637
199,774
413
325
92
$ 665,257
$ 583,894
$ 506,347
$
90.16
$
86.89
$
91.00
4.95
59.29
88.68
4.98
58.66
4.31
51.65
85.59
4.92
53.22
6.30
58.50
88.16
6.59
58.47
(1) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the
table above.
(2) Realized oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas
liquid content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other
factors affecting the price at the wellhead. The prices presented are based on actual results and are not calculated using
the rounded numbers presented in the table above.
(3) Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our
calculation of such after effects include current period settlements of matured commodity derivatives in accordance
with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to
instruments that settled in the period. The prices presented are based on actual results and are not calculated using the
rounded numbers presented in the table above.
56
The following table presents cash settlements received (paid) for matured commodity derivatives and premiums
incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of
the hedged prices presented above:
(in thousands)
Cash settlements received (paid) for matured commodity derivatives:
Oil ............................................................................................................................
Natural gas...............................................................................................................
Total.......................................................................................................................
Premiums paid attributable to contracts that matured during the respective period:
Oil ............................................................................................................................
Natural gas...............................................................................................................
Total.......................................................................................................................
$
$
$
$
For the years ended December 31,
2013
2012
2011
(149) $
4,195
4,046
$
(944) $
27,969
27,025
$
(7,973)
11,692
3,719
(7,970) $
(3,322)
(11,292) $
(5,278) $
(3,857)
(9,135) $
(1,549)
(2,555)
(4,104)
The changes in volumes and prices shown in the production, revenue and pricing table above caused the following
changes to our oil and natural gas revenue between the years ended December 31, 2011 and 2012 and 2013:
(in thousands)
2011 Revenue.............................................................................................................
Effect of changes in price ......................................................................................
Effect of changes in volumes.................................................................................
Other ......................................................................................................................
2012 Revenue.............................................................................................................
Effect of changes in price ......................................................................................
Effect of changes in volumes.................................................................................
Other ......................................................................................................................
2013 Revenue.............................................................................................................
Oil
Natural gas
Total net
dollar effect
of change
$
$
306,481
(19,627)
128,032
46
199,774 $
(77,904)
46,848
(81)
$
414,932 $
168,637 $
17,942
61,812
(10)
494,676
$
21,982
(20,688)
237
506,255
(97,531)
174,880
(35)
583,569
39,924
41,124
227
$
170,168
$
664,844
Oil and natural gas revenues. Our revenues are a function of oil and natural gas production volumes sold and
average sales prices received for those volumes. The total increase in oil and natural gas revenues of $81.3 million, or 14%, for
the year ended December 31, 2013 as compared to the year ended December 31, 2012 is largely due to a 15% increase in oil
production in our Permian area and an increase in both oil and natural gas prices realized for the year, which were offset by a
decrease in natural gas production volumes attributable to the divestiture of our Anadarko Basin assets and by severe winter
weather in the Permian region during the fourth quarter of 2013. The total increase in oil and natural gas revenues of $77.3
million, or 15%, for the year ended December 31, 2012 as compared to the year ended December 31, 2011 is largely due to a
42% increase in oil production and a 23% increase in natural gas production volumes attributable mainly to our Permian and
Anadarko Granite Wash areas, which were offset by lower prices received for oil and natural gas.
Transportation and treating. Our transportation and treating revenue from continuing operations increased by $0.09
million during the year ended December 31, 2013 as compared to the year ended December 31, 2012 and $0.2 million during
the year ended December 31, 2012 as compared to the year ended December 31, 2011. These increases were due to the sale of
condensate from our pipeline assets during each respective period, which occurs on an infrequent basis, as well as an increase
in the volumes transported through our pipeline.
57
Costs and expenses
The following table sets forth information regarding costs and expenses from continuing operations and average costs
per BOE for the periods presented:
(in thousands except for per BOE data)
Costs and expenses:
Lease operating expenses........................................................................................
Production and ad valorem taxes ............................................................................
Transportation and treating .....................................................................................
Transportation and treating - affiliates ....................................................................
Drilling and production...........................................................................................
General and administrative(1) ..................................................................................
Accretion of asset retirement obligations................................................................
Depletion, depreciation and amortization ...............................................................
Total costs and expenses..................................................................................
For the years ended December 31,
2013
2012
2011
$
79,136
$
67,325
$
42,396
37,637
680
891
2,688
89,696
1,475
162
—
2,452
62,106
1,200
43,306
31,982
65
—
2,675
51,064
616
233,944
241,072
174,119
$
450,906
$
411,954
$
303,827
Average costs per BOE:
Lease operating expenses........................................................................................
Production and ad valorem taxes ............................................................................
General and administrative(1) ..................................................................................
Depletion, depreciation and amortization ...............................................................
Total .................................................................................................................
_________________________________________________________________________
$
$
7.06
3.78
8.00
20.87
$
5.96
3.33
5.50
21.33
$
39.71 $
36.12 $
5.00
3.70
5.90
20.12
34.72
(1) General and administrative includes non-cash stock-based compensation of $21.4 million, $10.1 million and $6.1
million for the years ended December 31, 2013, 2012 and 2011, respectively. Excluding stock-based compensation
from the above metric results in general and administrative cost per BOE of $6.09, $4.61 and $5.19 for the years ended
December 31, 2013, 2012 and 2011, respectively.
Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $11.8 million,
or 18%, compared to a 1% decrease in production, for the year ended December 31, 2013 compared to 2012. On a per-BOE
basis, lease operating expenses increased in total to $7.06 per BOE as of December 31, 2013 from $5.96 per BOE as of
December 31, 2012. The increases were mainly due to (i) higher average lease operating expenses per-BOE on our higher oil-
weighted Permian production following the Anadarko Basin Sale and (ii) the implementation of best practices with respect to
workover operations. We expect that these practices will result in longer term well tubing integrity, which should improve
overall well performance and production in the long term, in addition to decreasing unit lease expenses as a result of reduced
well tubing failures.
Lease operating expenses, which include workover expenses, increased by $24.0 million, or 55%, compared to a 31%
increase in production, for the year ended December 31, 2012 compared to 2011. The increases were primarily due to an
increase in exploration and development activity, which resulted in additional producing wells during the year ended December
31, 2012 compared to 2011. The increase in well count also led to increases in routine repairs and maintenance. On a per-BOE
basis, lease operating expenses increased in total to $5.96 per BOE as of December 31, 2012 from $5.00 per BOE as of
December 31, 2011. The majority of the increase is mainly due to implementation of best practices with respect to workover
operations. We expect that these practices will result in longer term well tubing integrity, which should improve overall well
performance and production in the long term, in addition to decreasing unit lease expenses as a result of reduced well tubing
failures.
Production and ad valorem taxes. Production and ad valorem taxes increased to $42.4 million for the year ended
December 31, 2013 from $37.6 million for the year ended December 31, 2012, an increase of $4.8 million, or 13%. Our
production taxes are based on a percentage of our oil and natural gas revenue, and therefore increase in proportion to our oil and
natural gas revenues. Our ad valorem taxes have increased primarily as a result of increased valuations on our Texas properties
and an increase in the number of wells included in those valuations as a result of our 2012 and 2013 drilling activity in our
Permian and Anadarko Granite Wash areas.
58
Production and ad valorem taxes increased to $37.6 million for the year ended December 31, 2012 from $32.0 million
for the year ended December 31, 2011, an increase of $5.7 million, or 18%. Our ad valorem taxes have increased primarily as a
result of increased valuations on our Texas properties and an increase in the number of wells included in those valuations as a
result of our 2011 and 2012 drilling activity in our Permian and Anadarko Granite Wash areas.
Drilling and production. Drilling and production costs increased to $2.7 million for the year ended December 31,
2013 from $2.5 million for the year ended December 31, 2012 as a result of increased maintenance costs. Drilling and
production costs decreased to $2.5 million for the year ended December 31, 2012 from $2.7 million for the year ended
December 31, 2011 as a result of decreased maintenance costs.
General and administrative ("G&A"). G&A expense, excluding stock-based compensation, increased to $68.3
million as of December 31, 2013 from $52.1 million as of December 31, 2012, an increase of $16.2 million, or 31%. The
increase is primarily due to $17.5 million in additional salary, benefits and bonuses due to the growth of our business and
employee base. Additionally, the issuance of our cash-settled performance unit liability awards in February 2012 and 2013,
which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for $2.9 million of the total
increase. Computer, relocation, aircraft, rent and miscellaneous other expenses also contributed to the increase by $4.4 million
due to the growth of our business and employee base. The overall increase in G&A expense was offset by $11.0 million in
greater production income, capitalized salary and benefits, billable vehicle expense and lower professional fees, travel costs,
production data costs, and legal fees for 2013 as compared to 2012. On a per-BOE basis, G&A expense, excluding stock-based
compensation, increased to $6.09 per BOE during the year ended December 31, 2013 from $4.61 per BOE as of December 31,
2012. This increase was a result of the growth in our employee base combined with not as significant production growth due to
the divestiture of our Anadarko Basin assets.
G&A expense, excluding stock-based compensation, increased to $52.1 million as of December 31, 2012 from
$45.0 million as of December 31, 2011, an increase of $7.1 million, or 16%. The increase is primarily due to $6.4 million in
additional salary and benefits due to the growth of our business and employee base. Additionally, the issuance of our cash-
settled performance unit liability awards in February 2012, which are revalued at the end of each reporting period using a
Monte Carlo simulation, accounted for $1.8 million of the total increase. These increases were partially offset by a decrease in
legal and professional fees of $2.1 million for the year ended December 31, 2012, as we incurred higher fees in 2011 related to
the issuance of our 2019 senior unsecured notes in January 2011 and October 2011, the acquisition of Broad Oak in July 2011
and our IPO in December 2011. The remaining change is made up of smaller increases in a number of areas such as vehicle
expenses, insurance expenses and computer and software costs that are largely a result of increasing our workforce and growing
our business. On a per-BOE basis, G&A expense, excluding stock-based compensation, decreased to $4.61 per BOE during the
year ended December 31, 2012 from $5.19 per BOE as of December 31, 2011. This decrease was a result of a significant
increase in production during the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Employee compensation. Stock-based compensation increased to $21.4 million as of December 31, 2013 from
$10.1 million as of December 31, 2012, an increase of $11.4 million largely due to the issuance of 1,469,295 restricted stock
awards and 1,018,849 non-qualified restricted stock options during 2013. Additionally, during the year ended December 31,
2013, we accelerated the vestings of certain officers' and employees' restricted stock awards and restricted stock options awards
upon retirement or termination of employment due to the Anadarko Basin Sale. These modifications accounted for $4.7 million
of the stock-based compensation expense increase over the prior year.
Stock-based compensation increased to $10.1 million as of December 31, 2012 from $6.1 million as of December 31,
2011, an increase of $3.9 million due largely to the issuance of 932,084 restricted stock awards and 602,948 non-qualified
restricted stock options during 2012.
The performance unit awards increased in fair value by $4.1 million at year-end 2013 as compared to the year-end
2012, mainly as a result of the quarterly re-measurement, issuance of a new tranche of performance units during 2013 and the
performance of our stock price relative to our peer group utilized in the forward-looking Monte Carlo simulation. During the
year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in
2013. The cash payments for these performance unit awards were paid at $100.00 per unit totaling $2.1 million.
We have a 2011 Omnibus Equity Incentive Plan, which allows for the issuance of restricted stock awards, non-
qualified restricted stock option awards and performance unit awards to directors, officers, employees, consultants and advisers.
The fair value of the restricted stock awards issued during 2013 and 2012 was calculated based on the value of our stock price
on the date of grant in accordance with GAAP and is being recognized on a straight-line basis over the requisite service period
of the awards. The fair value of our non-qualified restricted stock option awards was determined using a Black-Scholes
valuation model in accordance with applicable GAAP accounting and is being recognized on a straight-line basis over the four-
year requisite service period of the awards. See Note E to our audited consolidated financial statements included elsewhere in
the Annual Report for additional information.
59
Depletion, depreciation and amortization ("DD&A"). DD&A was $233.9 million as of December 31, 2013 as
compared to $241.1 million as of December 31, 2012 and $174.1 million as of December 31, 2011.
The following table provides components of our DD&A expense from continuing operations for the periods presented:
(in thousands except for per BOE data)
For the years ended December 31,
2013
2012
2011
Depletion of proved oil and natural gas properties....................................................
Depreciation of pipeline assets ..................................................................................
Depreciation and amortization of fixed assets ...........................................................
DD&A....................................................................................................................
$
227,992
$
237,130
$
171,517
1,510
4,442
797
3,145
398
2,204
$
233,944 $
241,072 $
174,119
DD&A per BOE.........................................................................................................
$
20.87
$
21.33
$
20.12
The decrease in depletion of proved oil and natural gas properties of $9.1 million and $0.64 per BOE for the year
ended December 31, 2013 compared to 2012 is mainly a result of the Anadarko Basin Sale. We expect depletion of proved oil
and natural gas properties to increase as our focus remains on drilling higher-valued oil-rich assets. The increase in depletion of
proved oil and natural gas properties of $65.6 million and $1.16 per BOE for the year ended December 31, 2012 compared to
2011 resulted primarily from (i) decreases in the natural gas price between periods utilized to determine proved reserves,
(ii) increased net book value on new reserves added, (iii) higher total production levels and (iv) increased capitalized costs for
new wells completed in 2012.
Non-operating income and expense. The following table sets forth the components of non-operating income and
expense from continuing operations for the periods presented:
(in thousands)
Non-operating income (expense):
For the years ended December 31,
2013
2012
2011
Gain (loss) on derivatives:
Commodity derivatives, net ..................................................................................
Interest rate derivatives, net ..................................................................................
Income from equity methods investee .......................................................................
Interest expense..........................................................................................................
Interest and other income...........................................................................................
Write-off of deferred loan costs.................................................................................
Loss on disposal of assets ..........................................................................................
Non-operating expense, net ..............................................................................
$
$
$
79,902
(24)
29
(100,327)
163
(1,502)
(1,508)
(23,267) $
$
8,800
(412)
—
(85,572)
59
—
(51)
(77,176) $
21,047
(1,311)
—
(50,580)
108
(6,195)
(1)
(36,932)
Commodity derivatives. Total gain on commodity derivatives increased by $71.1 million for the year ended
December 31, 2013 compared to 2012 and decreased $12.2 million for the year ended December 31, 2012 compared to 2011.
Net cash settlements on matured commodity derivatives decreased by $23.0 million for the year ended December 31, 2013
compared to 2012 and increased $23.3 million for the year ended December 31, 2012 compared to 2011, based on the cash
settlement prices of our matured commodity derivatives compared to the prices specified in the derivative contracts.
Additionally, during the current year, we received net cash settlements on early terminations and modifications of derivatives of
$6.0 million as a result of unwinding nine natural gas commodity contracts in connection with the Anadarko Basin Sale. There
were no comparable amounts in 2012.
The change in fair value of commodity derivatives still held increased by $88.1 million for the year ended December
31, 2013 compared to 2012 and decreased $35.5 million for the year ended December 31, 2012 compared to 2011. This
increase is mainly due to our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International
Petroleum Exchange index oil prices, which was entered into during 2013 and was valued at $92.8 million at December 31,
2013. We subsequently settled this contract in February 2014. Refer to Note O of our audited consolidated financial statements
included elsewhere in this Annual Report for additional information regarding this subsequent event. The remainder of the
change in the fair value of commodity derivatives still held is a result of the changing relationships between our contract prices
and the associated forward curves used to calculate the fair value of our commodity derivatives in relation to expected market
60
prices. In general, we experience gains during periods of decreasing market prices and losses during periods of increasing
market prices.
See Notes B.6, G and H to our audited consolidated financial statements included elsewhere in this Annual Report and
“Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our commodity
derivatives.
Income from equity methods investee. Income from equity methods investee increased by $0.03 million for the year
ended December 31, 2013 compared to 2012. This increase is due to our 2013 equity method investment, which had profits
during its first year of operation. See Note M to our audited consolidated financial statements included elsewhere in the Annual
Report for additional information.
Interest expense and gains and losses on interest rate swaps. Interest expense increased by $14.8 million, or 17%,
for the year ended December 31, 2013 compared to 2012, and $35.0 million, or 69%, for the year ended December 31, 2012
compared to 2011. These increases are largely due to the issuance of (i) $200.0 million of 9 1/2% senior unsecured notes due
2019 in October of 2011 in addition to the previously outstanding $350.0 million of 9 1/2% senior unsecured notes due in 2019,
and (ii) $500.0 million of 7 3/8% senior unsecured notes due 2022 in April of 2012.
The table below shows the changes in the significant components of interest expense for the periods presented:
(in thousands)
Year ended
December 31, 2013
compared to 2012
Year ended
December 31, 2012
compared to 2011
Changes in interest expense:
Senior Secured Credit Facility, net of capitalized interest(1)..............................................
2019 senior unsecured notes..............................................................................................
2022 senior unsecured notes..............................................................................................
Broad Oak credit facility(2) ................................................................................................
Change in net present value of deferred premiums paid for derivatives............................
Amortization of deferred loan costs...................................................................................
Other ..................................................................................................................................
Total change in interest expense...................................................................................
$
$
_______________________________________________________________________
2,931
(20)
12,189
—
(206)
168
(307)
14,755
$
$
(3,497)
16,661
24,686
(4,928)
197
1,327
546
34,992
(1) The Senior Secured Credit Facility was paid in full on August 1, 2013 and remained undrawn for the remainder of the
year ended December 31, 2013.
(2) The Broad Oak credit facility was paid-in-full and terminated on July 1, 2011 in connection with the Broad Oak
acquisition.
We had entered into certain variable-to-fixed interest rate derivatives that hedge our exposure to interest rate variations
on our variable interest rate debt that expired in September 2013. During the year ended December 31, 2013 and 2012, we had
one interest rate swap and one interest rate cap outstanding for a total notional amount of $100.0 million with fixed pay rates
ranging from 1.11% to 3.00% until their expiration in September 2013.
Loss on disposal of assets. Loss on disposal of assets increased by $1.5 million for the year ended December 31,
2013 compared to 2012 and $0.05 million for the year ended December 31, 2012 compared to 2011. The 2013 increase over the
prior year is largely due to losses sustained from a fire at a truck station on one of our properties and a loss on disposal of a
portion of our inventory. These losses were offset by a gain of $3.2 million on the pipeline assets and various other associated
property and equipment disposed of in the Anadarko Basin Sale.
Write-off of deferred loan costs. In August 2013, we wrote-off $1.5 million in deferred loan costs as a result of
changes in the borrowing base under the Senior Secured Credit Facility due to the Anadarko Basin Sale. As of December 31,
2013, the borrowing base of our Senior Secured Credit Facility was $925.0 million with an aggregated elected commitment of
$825.0 million.
In January 2011, we used a portion of the net proceeds from the issuance of our 2019 senior unsecured notes to pay in
full and retire our term loan. Additionally, concurrent with the issuance of our senior unsecured notes in January 2011, the
amount available for borrowings under our Senior Secured Credit Facility was decreased. As a result, in January 2011, we took
a charge to expense for the debt issuance costs attributable to our term loan and a proportionate percentage of the costs incurred
for our Senior Secured Credit Facility, which totaled $2.9 million and $0.3 million, respectively.
61
On July 1, 2011, in conjunction with the Broad Oak acquisition, the Broad Oak credit facility was paid in full and
terminated and the related debt issuance costs of $2.9 million were charged to expense.
Income tax expense. We recorded a deferred income tax expense from continuing operations of $74.5 million, $33.0
million and $59.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, due to fluctuations in income
before income taxes as shown in the table below.
(in thousands)
For the years ended December 31,
2013
2012
2011
Income from continuing operations before income taxes..........................................
Income tax expense....................................................................................................
Income from continuing operations, net..................................................................
Effective tax rate ........................................................................................................
$ 191,084
(74,507)
$ 116,577
$
$
94,764
(33,003)
61,761
$ 165,588
(59,612)
$ 105,976
39%
35%
36%
Our effective tax rate is based on our annual permanent tax differences and annual pre-tax book income. The
Company's effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given
year, but are not consistent from year to year. During the year ended December 31, 2013, certain shares related to restricted
stock awards vested at times when our stock price was lower than the fair value of those shares at the time of grant. As a result,
the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the
year ended December 31, 2013, certain restricted stock options were exercised. The income tax deduction related to the options'
intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls
reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, we have not
previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.6 million for the year
ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no
comparative amounts for the years ended December 31, 2012 or 2011.
Income from discontinued operations, net of tax. The table below shows our income from discontinued operations
for the periods presented:
(in thousands)
Income (loss) from discontinued operations, net of tax ....................................
For the years ended December 31,
2013
2012
2011
$
1,423
$
(107) $
(422)
Income (loss) from discontinued operations, net of tax, increased by $1.5 million for the year ended December 31,
2013 compared to 2012 and $0.3 million for the year ended December 31, 2012 compared to 2011. The increases are a result of
increased production over time that has attributed to our growth in transportation and gathering revenue. The majority of our
discontinued operations was a significant portion of Laredo Midstream's operations, which was included in the Anadarko Basin
Sale.
Our loss from discontinued operations, net of tax for the year ended December 31, 2011, is inclusive of impairment
expense of $0.2 million to reflect our materials and supplies inventory at the lower of cost or market value calculated as of
December 31, 2011. It was determined for the years ended December 31, 2013 and 2012, that a lower of cost or market
adjustment was not needed for materials and supplies.
Liquidity and capital resources
Since our IPO, our primary sources of liquidity have been cash flows from operations, proceeds from our IPO,
proceeds from our senior unsecured notes offerings, borrowings under our Senior Secured Credit Facility, proceeds from the
Anadarko Basin Sale and proceeds from our Follow-on Offering. Our primary use of capital has been for the exploration,
development and acquisition of oil and natural gas properties.
On March 22, 2013, we filed a shelf registration statement, which became automatically effective, that permits us to
sell equity and/or debt in one or more offerings of an indeterminate aggregate amount. As we pursue reserves and production
growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future
financial obligations, capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and
production will be highly dependent on the capital resources available to us. We continually monitor market conditions and may
consider issuing more equity or taking on additional debt.
62
On January 23, 2014, we completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior
notes due 2022, which will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-
annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014.
As of December 31, 2013, we had no amounts of principal outstanding under our Senior Secured Credit Facility and
$1.05 billion in senior unsecured notes, excluding the unamortized premium of $1.5 million received on the October 2011
offering of our 2019 senior unsecured notes. We had $825.0 million available for borrowings under our Senior Secured Credit
Facility and $198.2 million in cash on hand for total available liquidity of $1.0 billion as of December 31, 2013. We believe
such availability as well as cash flows from operations provide us with the ability to implement our planned exploration and
development activities. As a result of the issuance of the new senior unsecured notes on January 23, 2014, the borrowing base
under our Senior Secured Credit Facility was reduced to $812.5 million.
As of February 26, 2014 we had $1.5 billion in debt outstanding (including the new senior unsecured notes), $812.5
million available for borrowings under our Senior Secured Credit Facility, and $624.2 million in cash on hand for total available
liquidity of $1.4 billion.
We expect, in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows
from operations despite possible declines in the price of oil and natural gas. Please see "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" below.
Cash flows
Our cash flows from continued and discontinued operations for the periods presented are as follows:
(in thousands)
For the years ended December 31,
2013
2012
2011
Net cash provided by operating activities..................................................................
Net cash used in investing activities ..........................................................................
Net cash provided by financing activities..................................................................
Net increase (decrease) in cash................................................................................
$
$
364,729
(329,884)
130,084
376,776
(940,751)
569,197
$
$
164,929
$
5,222
$
344,076
(706,787)
359,478
(3,233)
The results of operations of the pipeline assets and various other associated property and equipment sold as a
component of the Anadarko Basin Sale have been presented as results of discontinued operations, net of tax. We do not disclose
discontinued operations separately from cash flows from continued operations due to the immateriality of the cash flows from
discontinued operations. The absence of these discontinued operations will not materially affect future liquidity or capital
resources.
Cash flows provided by operating activities
Net cash provided by operating activities was $364.7 million, $376.8 million and $344.1 million for the years ended
December 31, 2013, 2012 and 2011, respectively. The decrease of $12.0 million from 2012 to 2013 is largely due to an increase
in our gains on derivatives and various expense items, which were offset by our increased revenues due to production growth
driven by our successful drilling program as well as increases in the market prices for oil and natural gas. The increase of
$32.7 million from 2011 to 2012 was largely due to significant increases in revenue due to production growth driven by our
successful drilling program, offset by decreases in the market prices for oil and natural gas.
Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels
and the variability of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure, capacity to
reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors
are not within our control and are difficult to predict. For additional information on the impact of changing prices on our
financial position, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
63
Cash flows used in investing activities
Our cash used in investing activities for acquisitions and capital expenditures and our proceeds from asset disposals for
the periods presented are summarized in the table below.
(in thousands)
Acquisitions ...............................................................................................................
Capital expenditures:
Investment in equity method investee .....................................................................
Oil and natural gas properties..................................................................................
Pipeline and gathering assets...................................................................................
Other fixed assets ....................................................................................................
Proceeds from other asset disposals...........................................................................
Net cash used in investing activities .....................................................................
For the years ended December 31,
2013
2012
2011
$
(33,710) $
(20,496) $
—
(3,287)
(702,349)
(24,409)
(16,257)
450,128
—
(687,062)
(13,368)
(6,413)
56
$ (329,884) $ (940,751) $ (706,787)
—
(895,312)
(16,241)
(8,755)
53
Net cash flows used in investing activities were $329.9 million, $940.8 million and $706.8 million for the years ended
December 31, 2013, 2012 and 2011, respectively. The decrease of $610.9 million from 2012 to 2013 was largely due to the
proceeds we received from the Anadarko Basin Sale as well as decreased capital expenditures for 2013 compared to 2012. The
increase of $234.0 million from 2011 to 2012 was due to (i) an increase in our drilling efforts in our Permian Basin and
Anadarko Granite Wash areas in order to take advantage of strategic vertical and horizontal drilling opportunities, (ii) the
increased stabilization of oil prices and (iii) additional efforts on delineation drilling.
Capital expenditure budget
Our board of directors approved a budget of approximately $1.0 billion for calendar year 2014, excluding acquisitions.
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
The amount, timing and allocation of capital expenditures are largely discretionary and within management's control.
If oil and natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels,
we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance
between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and
potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of
opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to
success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs,
industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash
flow and other factors both within and outside our control.
64
Cash flows provided by financing activities
Our cash provided by financing activities for the periods presented is summarized in the table below.
(in thousands)
Broad Oak transaction...............................................................................................
Borrowings on revolving credit facilities..................................................................
Payments on revolving credit facilities .....................................................................
Payments on term loan ..............................................................................................
Issuance of 2019 Notes .............................................................................................
Issuance of 2022 Notes .............................................................................................
Proceeds from issuance of common stock, net of offering costs ..............................
Purchase of equity interests and units, net ................................................................
Proceeds from exercise of employee stock options ..................................................
Purchase of treasury stock.........................................................................................
Payments for loan costs.............................................................................................
Net cash provided by financing activities .......................................................
For the years ended December 31,
2013
2012
2011
$
— $
— $
230,000
(395,000)
—
—
—
298,104
—
2,050
(2,083)
(2,987)
130,084
$
360,000
(280,000)
—
—
500,000
—
—
—
—
(10,803)
569,197
$
$
(81,963)
790,100
(1,096,700)
(100,000)
552,000
—
319,378
(164)
—
(3)
(23,170)
359,478
Net cash provided by financing activities for the year ended December 31, 2013 was the result of proceeds from the
Follow-on Offering of $298.1 million and proceeds from the exercise of employee stock options of $2.1 million. These cash
inflows were partially offset by the $165.0 million net payments on our Senior Secured Credit Facility, payments for loan costs
totaling $3.0 million and the purchase of treasury stock to satisfy employee tax withholding obligations that arise upon the lapse
of restrictions on restricted stock totaling $2.1 million.
For the year ended December 31, 2012, net cash provided by financing activities was primarily the result of $500.0
million in gross proceeds from the issuance of our 2022 senior unsecured notes on April 27, 2012 and net borrowings on our
Senior Secured Credit Facility of $80.0 million. These cash inflows were partially offset by payments of $10.8 million for loan
costs.
For the year ended December 31, 2011, net cash provided by financing activities was primarily the result of
$552.0 million in gross proceeds from the issuance of our 2019 senior unsecured notes of $350.0 million on January 20, 2011
and $202.0 million on October 19, 2011, net proceeds from our IPO of $319.4 million, net payments on our Senior Secured
Credit Facility and former Broad Oak credit facility totaling $306.6 million, the payment of $100.0 million to pay in full and
terminate our term loan and payments of $23.2 million for loan costs. Additionally, we incurred $82.0 million in debt to
facilitate the Broad Oak acquisition.
Debt
As of December 31, 2013, we were a party only to our Senior Secured Credit Facility and the indentures governing our
2019 and 2022 senior unsecured notes. The Broad Oak credit facility was terminated on July 1, 2011 in conjunction with the
Broad Oak acquisition. Our term loan facility was paid in full and retired in conjunction with the closing of the January 2011
offering of our 2019 senior unsecured notes.
Senior Secured Credit Facility. As of December 31, 2013, our Senior Secured Credit Facility, which matures
November 4, 2018, had a capacity of $2.0 billion and a borrowing base of $925.0 million with an aggregate elected
commitment of $825.0 million and no amounts outstanding.
Principal amounts borrowed under the Senior Secured Credit Facility are payable on the final maturity date with such
borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate
or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-
month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered
Rate ("LIBOR"), in each case, plus an applicable margin based on the ratio of the outstanding amount on the Senior Secured
Credit Facility to the elected commitment. We are also required to pay an annual commitment fee on the unused portion of the
bank's commitment of 0.375% to 0.5%.
65
As of December 31, 2013, 2012 and 2011, borrowings outstanding under our Senior Secured Credit Facility totaled
zero, $165.0 million and $85.0 million, respectively. As of February 26, 2014, no amounts were outstanding under our Senior
Secured Credit Facility and the amount available for borrowings was $812.5 million.
Our Senior Secured Credit Facility is secured by a first-priority lien on our assets, including oil and natural gas
properties constituting at least 80% of the present value of our proved reserves owned now or in the future. As of December 31,
2013, we were subject to the following financial and non-financial ratios on a consolidated basis:
•
•
a current ratio at the end of each fiscal quarter, as defined by the agreement, that is not permitted to be less than
1.00 to 1.00; and
at the end of each fiscal quarter, the ratio of earnings before interest, taxes, depreciation, depletion, amortization
and exploration expenses and other non-cash charges ("EBITDAX") for the four fiscal quarters ending on the
relevant date to the sum of net interest expense plus letter of credit fees, in each case for such period, is not
permitted to be less than 2.50 to 1.00.
Our Senior Secured Credit Facility contains both financial and non-financial covenants. We were in compliance with
these covenants as of December 31, 2013, 2012 and 2011.
Our Senior Secured Credit Facility contains various covenants that limit our ability to:
•
•
•
incur indebtedness;
pay dividends and repay certain indebtedness;
grant certain liens;
• merge or consolidate;
•
•
engage in certain asset dispositions;
use proceeds for any purpose other than to finance the acquisition, exploration and development of mineral
interests and for working capital and general corporate purposes;
• make certain investments;
•
•
•
•
•
•
enter into transactions with affiliates;
engage in certain transactions that violate ERISA or the Internal Revenue Code or enter into certain employee
benefit plans and transactions;
enter into certain swap agreements or hedge transactions;
incur, become or remain liable under any operating lease which would cause rentals payable to be greater than
$10.0 million in a fiscal year;
acquire all or substantially all of the assets or capital stock of any person, other than assets consisting of oil and
natural gas properties and certain other oil and natural gas related acquisitions and investments; and
repay or redeem our senior unsecured notes, or amend, modify or make any other change to any of the terms in
our senior unsecured notes that would change the term, life, principal, rate or recurring fee, add call or pre-
payment premiums, or shorten any interest periods.
As of December 31, 2013, we were in compliance with the terms of our Senior Secured Credit Facility. If an event of
default exists under our Senior Secured Credit Facility, the lenders will be able to accelerate the maturity of our Senior Secured
Credit Facility and exercise other rights and remedies. As of December 31, 2013, each of the following would be an event of
default:
•
•
•
•
•
failure to pay any principal of any note or any reimbursement obligation under any letter of credit when due or
any interest, fees or other amount within certain grace periods;
failure to perform or otherwise comply with the covenants in the Senior Secured Credit Facility and other loan
documents, subject, in certain instances, to certain grace periods;
a representation, warranty, certification or statement is proved to be incorrect in any material respect when made;
failure to make any payment in respect of any other indebtedness in excess of $25.0 million, any event occurs that
permits or causes the acceleration of any such indebtedness or any event of default or termination event under a
hedge agreement occurs in which the net hedging obligation owed is greater than $25.0 million;
voluntary or involuntary bankruptcy or insolvency events involving us or our subsidiary and in the case of an
involuntary proceeding, such proceeding remains undismissed and unstayed for the applicable grace period;
66
•
•
•
•
•
•
one or more adverse judgments in excess of $25.0 million to the extent not covered by acceptable third party
insurers, are rendered and are not satisfied, stayed or paid for the applicable grace period;
incurring environmental liabilities which exceed $25.0 million to the extent not covered by acceptable third party
insurers;
the loan agreement or any other loan paper ceases to be in full force and effect, or is declared null and void, or is
contested or challenged, or any lien ceases to be a valid, first priority, perfected lien;
failure to cure any borrowing base deficiency in accordance with the Senior Secured Credit Facility;
a change of control, as defined in our Senior Secured Credit Facility; and
notification if an "event of default" shall occur under the indentures governing our senior unsecured notes.
Additionally, our Senior Secured Credit Facility provides for the issuance of letters of credit, limited in the aggregate
to the lesser of $20.0 million and the total availability under the facility. No letters of credit were outstanding as of December
31, 2013.
Termination of the Broad Oak credit facility. At June 30, 2011, Broad Oak had a $600.0 million revolving credit
facility under its seventh amendment executed on February 1, 2011 between Broad Oak and certain financial institutions. Under
the seventh amendment, the borrowing base was redetermined at $375.0 million. As defined in the Broad Oak credit facility, the
Adjusted Base Rate Advances and Eurodollar Advances under the facilities bore interest payable quarterly at an Adjusted Base
Rate or Adjusted LIBOR plus an applicable margin based on the ratio of outstanding revolving credit to the conforming
borrowing base. At June 30, 2011, the applicable margin rates were 1.50% for the Adjusted Base Rate advances and 2.50% for
the Eurodollar advances. Additionally, Broad Oak was also required to pay a quarterly commitment fee of 0.5% on the unused
portion of the bank's commitment. The Broad Oak credit facility was secured by a first priority lien on Broad Oak's oil and
natural gas properties. Concurrently with the Broad Oak acquisition on July 1, 2011, the Broad Oak credit facility was paid in
full and terminated.
Senior unsecured notes. On January 20, 2011 and October 19, 2011, Laredo Petroleum, Inc. completed the offerings
of $350.0 million principal amount and $200.0 million principal amount, respectively, 9 1/2% senior unsecured notes due 2019.
The 2019 senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable
semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 senior unsecured notes were fully and
unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and its
subsidiaries (other than Laredo Petroleum, Inc.) (collectively, the “guarantors”), and, following the Internal Consolidation, they
are fully and unconditionally guaranteed on a senior unsecured basis by Laredo Midstream. Our 2019 senior unsecured notes
were issued under and are governed by an indenture dated January 20, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank,
National Association, as trustee, and the guarantors (as supplemented, the “2011 indenture”). The 2011 indenture contains
customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of
dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness
under our 2019 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the
2011 indenture.
On April 27, 2012, Laredo Petroleum, Inc. completed an offering of $500.0 million aggregate principal amount of
7 3/8% senior unsecured notes due 2022. The 2022 senior unsecured notes will mature on May 1, 2022 and bear an interest rate
of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing
November 1, 2012. The 2022 senior unsecured notes were fully and unconditionally guaranteed, jointly and severally, on a
senior unsecured basis by Laredo Petroleum Holdings, Inc. and the guarantors, and, following the Internal Consolidation, they
are fully and unconditionally guaranteed on a senior unsecured basis by Laredo Midstream. Our 2022 senior unsecured notes
were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as
further supplemented, the “2012 indenture”), among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as
trustee, and the guarantors. The 2012 indenture contains customary terms, events of default and covenants relating to, among
other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with
affiliates and limitations on asset sales. Indebtedness under our 2022 senior unsecured notes may be accelerated in certain
circumstances upon an event of default as set forth in the 2012 indenture. The net proceeds from the 2022 senior unsecured
notes were used (i) to pay in full $280.0 million outstanding under our Senior Secured Credit Facility, and (ii) for general
working capital purposes.
Refer to Note D of our audited consolidated financial statements included elsewhere in this Annual Report for further
discussion of the 2019 senior unsecured notes and the 2022 senior unsecured notes.
On January 23, 2014, Laredo completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior
unsecured notes due 2022, which will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and
67
payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The notes are
guaranteed on a senior unsecured basis by Laredo Midstream and certain of our future restricted subsidiaries. As a result of the
issuance of these notes, the amount available for borrowings under our Senior Secured Credit Facility was decreased to $812.5
million.
As of February 26, 2014, we had a total of $1.5 billion of senior unsecured notes outstanding.
Obligations and commitments
We had the following significant contractual obligations and commitments that will require capital resources as of
December 31, 2013:
(in thousands)
Senior Secured Credit Facility(1) ................................
2019 and 2022 Senior unsecured notes(2) ...................
Drilling rig commitments(3) ........................................
Derivatives(4) ..............................................................
Asset retirement obligations(5)....................................
Office and equipment leases(6)....................................
Performance unit liability awards(7) ...........................
Capital contribution commitment to equity method
investee(8)....................................................................
Total .........................................................................
Payments due
Less than
1 year
1 - 3 years
3 - 5 years
More than
5 years
Total
$
— $
— $
— $
— $
—
89,125
40,799
7,419
265
1,994
—
25,693
178,250
178,250
1,205,188
1,650,813
—
5,524
2,399
4,011
4,450
—
—
—
1,250
3,561
—
—
—
—
17,829
1,367
—
—
40,799
12,943
21,743
10,933
4,450
25,693
$
165,295
$
194,634
$
183,061
$ 1,224,384
$ 1,767,374
___________________________________________________________________________
(1) As of December 31, 2013, our Senior Secured Credit Facility had no amounts outstanding.
(2) Values presented include both our principal and interest obligations.
(3) As of December 31, 2013, we had several drilling rigs under term contracts which expire during 2014. Any other rig
performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the
conclusion of drilling on the current well. Therefore, drilling obligations on well-by-well rigs have not been included
in the table above. The value in the table represents the gross amount that we are committed to pay. However, we will
record our proportionate share based on our working interest in our audited consolidated financial statements as
incurred. See Note J to our audited consolidated financial statements included elsewhere in this Annual Report for
additional discussion of our drilling contract commitments.
(4) Represents payments due for deferred premiums on our commodity hedging contracts.
(5) Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years
into the future, estimating these future costs requires management to make estimates and judgments that are subject to
future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and
regulatory environment. See Note B to our audited consolidated financial statements included elsewhere in this Annual
Report.
(6) See Note J to our audited consolidated financial statements included elsewhere in this Annual Report for a description
of lease obligations.
(7) Represents cash awards that were granted on February 3, 2012 and February 15, 2013 under the 2011 Omnibus Equity
Incentive Plan. The payout of the performance units is dependent upon our relative total shareholder return
performance against a set of peers and will be paid out in 2015 and 2016. See Note B to our audited consolidated
financial statements included elsewhere in this Annual Report for additional discussion of our performance units.
(8) See Note M to our consolidated financial statements included elsewhere in this Annual Report for a discussion of our
equity method investee.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated
financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial
statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and
expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and
68
uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported
under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular
basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that
are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation
of our consolidated financial statements. We believe these accounting policies reflect our more significant estimates and
assumptions used in preparation of our consolidated financial statements. See Note B to our consolidated financial statements
included elsewhere in this Annual Report for a discussion of additional accounting policies and estimates made by
management.
Method of accounting for oil and natural gas properties
The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas
industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts
method and the full cost method. We follow the full cost method of accounting under which all costs associated with property
acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly
identified with our acquisition, exploration and development activities and do not include any costs related to production,
general corporate overhead or similar activities.
Under the full cost method, capitalized costs are amortized on a composite unit of production method based on proved
oil and natural gas reserves. If we maintain the same level of production year over year, the depletion, depreciation and
amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes
significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve
a significant change in the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs
of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated
properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and
otherwise if impairment has occurred.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent reserve engineers prepare the estimates of oil and natural gas reserves and associated future net cash
flows. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic
and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in
the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also
change substantially over time as a result of numerous factors, including additional development activity, evolving production
history and a continual reassessment of the viability of production under changing economic conditions. As a result, material
revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve
estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for
various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could
significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
Revenue recognition
Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer
has taken title and assumed the risks and rewards of ownership and collectability is reasonably assured. The sales prices for oil
and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or
historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual
charges based on third party documents. Since there is a ready market for oil and natural gas, we sell the majority of production
soon after it is produced at various locations.
Variable interest entities
An entity is referred to as a variable interest entity ("VIE") pursuant to accounting guidance for consolidation if it
possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii)
the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual
economics, or (v) the entity was established with non-substantive voting interests. We would consolidate a VIE when we are the
primary beneficiary of a VIE. A primary beneficiary has the power to direct the activities that most significantly impact the
activities of the VIE and the right to receive the benefits or the obligation to absorb the losses of the entity that could be
potentially significant to the VIE. We continually monitor our unconsolidated VIE exposure in order to determine if any events
have occurred that could cause the primary beneficiary to change. See Note M to our consolidated financial statements included
elsewhere in this Annual Report for a discussion of our unconsolidated VIE.
69
Impairment of oil and natural gas properties
We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a
quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated
future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any
related income tax effects. For the years ended December 31, 2013, 2012 and 2011, the result of the ceiling test concluded that
the carrying amount of our oil and natural gas properties was significantly below the calculated ceiling test value and as such,
our properties were not impaired and a write-down was not required. In calculating future net revenues, current prices are
calculated as the average oil and natural gas prices during the 12-month period prior to the end of the current reporting period,
determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are
those as of the end of the appropriate quarterly period.
Asset retirement obligations
In accordance with the Financial Accounting Standard Board's (the "FASB") authoritative guidance on asset retirement
obligations ("ARO"), we record the fair value of a liability for a legal obligation to retire an asset in the period in which the
liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset.
For oil and natural gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated
amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with
applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit
of production method. The accretion expense is recorded as a component of depletion, depreciation and amortization in our
consolidated statement of operations.
We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the
future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as
what constitutes adequate restoration. Included in the fair value calculation are assumptions and judgments including the
ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the
existing ARO liability, a corresponding adjustment is made to the related asset.
Derivatives
We record all derivatives on the balance sheet as either assets or liabilities measured at their estimated fair value. We
have not designated any derivatives as hedges for accounting purposes and we do not enter into such instruments for
speculative trading purposes. Gains and losses from the settlement of commodity derivatives and gains and losses from
valuation changes in the remaining unsettled commodity derivatives are reported under "Non-operating income (expense)" in
our consolidated statements of operations.
Stock-based compensation
We measure stock-based compensation expense at the grant date based on the fair value of an award and recognize the
compensation expense on a straight-line basis over the service period, which is usually the vesting period. The fair value of the
awards is based on the value of our common stock on the date of grant. The determination of the fair value of an award requires
significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the
expected life of the award and forfeiture rate assumptions. Beginning in the first quarter of 2012, we utilized the Black-Scholes
option pricing model to measure the fair value of stock options granted under our 2011 Omnibus Equity Incentive Plan. As
there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there
is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. Refer to
Note E of our consolidated financial statements included elsewhere in this Annual Report for additional information regarding
our stock-based compensation.
Performance unit compensation
For performance unit awards issued to management, we utilized a Monte Carlo simulation prepared by an independent
third party to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each
reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is
based on the stock prices' expected volatility. The performance unit awards are classified as liability awards as they have a
combination of performance and service criteria and will be settled in cash at the end of the requisite service period based on
the achievement of certain performance criteria. The liability and related compensation expense for each period for these
awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata
share for the period for which service has already been provided. Compensation expense for the performance units is included
70
in “General and administrative” expense in our consolidated statements of operations with the corresponding liability recorded
in the “Other noncurrent liabilities” section of our consolidated balance sheet. As there are inherent uncertainties related to the
factors and our judgment in applying them to the fair value determinations, there is risk that the recorded performance unit
compensation may not accurately reflect the amount ultimately earned by the member of management. Refer to Note E of our
consolidated financial statements included elsewhere in this Annual Report for additional information regarding our
performance unit awards.
Income taxes
As of December 31, 2013, we had a deferred tax liability of $12.7 million and as of December 31, 2012 and 2011, we
had deferred tax assets of $62.6 million and $95.6 million, respectively.
As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and
state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax
exposure together with assessing temporary differences resulting from differing treatment of items such as derivative
instruments, depletion, depreciation and amortization, and certain accrued liabilities for tax and financial accounting purposes.
These differences and our net operating loss carry-forwards result in deferred tax assets and liabilities, which are included in
our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the
deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a
valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a
period, we must include an expense or reduction of expense within the tax provision in the consolidated statement of
operations.
Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of
negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be
commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more
positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed
for all or a portion of the deferred tax asset. Among the more significant types of evidence that we consider are:
•
•
•
•
•
our earnings history exclusive of the loss that created the future deductible amount coupled with evidence
indicating that the loss is an aberration rather than a continuing condition;
the ability to recover our net operating loss carry-forward deferred tax assets in future years;
the existence of significant proved oil and natural gas reserves;
our ability to use tax planning strategies as well as current price protection utilizing oil and natural gas hedges;
and
future revenue and operating cost projections that indicate we will produce more than enough taxable income to
realize the deferred tax asset based on existing sales prices and cost structures.
During 2013, in evaluating whether it was more-likely-than-not that our deferred tax asset was recoverable from future
net income, we considered our strong earnings history for the current and most recent two years.
We also determined through our analysis that our net operating loss carry-forward deferred tax asset was recoverable
over future years and that we had no material net operating losses expiring prior to 2026. In performing our analysis, we used
inputs from third party sources, which came primarily from our reserve reports that were independently estimated by a third
party engineer. Based on our forecasted results from multiple analyses, as of December 31, 2013 and 2012, future taxable
income from our oil and natural gas reserves is expected to be sufficient to utilize the entire net operating loss carry-forward in
approximately seven to ten years. We believe this analysis provides significant positive evidence that is objectively verifiable,
as it uses three-year historical operating results to predict future taxable income. We considered all applicable tax deductions in
our analysis which were substantially known and were not subject to significant estimates.
As of December 31, 2013, we had charitable contribution carry-forwards of $0.4 million, which will begin to expire in
2013. The utilization of charitable contributions for any tax year is limited to 10% of taxable income without regard to
charitable contributions, net operating losses, and dividend received deductions. A corporation is permitted to carry-over to the
five succeeding tax years contributions that exceeded the 10% limitation, but deductions in those years are also subject to the
maximum limitation. Based on our analysis, we do not believe it is more-likely-than-not that we will utilize the carry-forward
in its entirety before expiration, therefore, a full valuation allowance of $0.1 million has been recorded against the related
deferred tax asset.
71
Based on our analysis, we determined as of December 31, 2013 that given the proper weight of the positive evidence
noted above, it was more-likely-than-not that our deferred tax asset would be recovered with the exception of the deferred tax
asset related to the charitable contribution carry-over.
We will continue to assess the need for a valuation allowance against deferred tax assets considering all available
evidence obtained in future reporting periods. If our assumptions regarding forecasted production, pricing and margins are not
achieved by amounts in excess of our sensitivity analysis, it may have a significant impact on the corresponding taxable income
which may require a valuation allowance to be recorded against our deferred tax assets at that time.
Income tax windfalls and shortfalls. For certain stock-based compensation awards that are expected to result in a tax
deduction under existing tax law, a deferred tax asset is established as we recognize compensation cost for book purposes. Book
compensation cost is determined on the grant date and recognized over the award's requisite service period, whereas the related
tax deduction is measured on the vesting date for restricted stock and on the exercise date for stock options. The corresponding
deferred tax asset also is measured on the grant date and recognized over the service period. As a result, there will almost
always be a difference in the amount of compensation cost recognized for book purposes versus the amount of tax deduction
that a company may receive. If the tax deduction exceeds the cumulative book compensation cost that we recognized, the tax
benefit associated with any excess deduction will be considered an excess benefit or windfall and will be recognized as
additional paid-in capital (“APIC”). If the tax deduction is less than the cumulative book compensation cost, the tax effect of
the resulting difference is a deficiency or shortfall, and should be charged first to APIC, to the extent of our pool of windfall tax
benefits, with any remainder recognized in income tax expense. We utilize a one-pool approach when accounting for the pool of
windfall tax benefits. In the one-pool approach, employees and non-employees are grouped into a single pool. As of December
31, 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits have been
recognized.
Recent accounting pronouncements
In July 2013, the FASB issued guidance on the presentation of unrecognized tax benefits when a net operating loss
carry-forward, a similar tax loss, or a tax credit carry-forward exists at the reporting date. This guidance is effective for fiscal
years, and interim periods within those years, beginning after December 15, 2013. We do not expect the adoption to have an
impact on our consolidated financial statements.
Inflation
Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of
operations for the period from December 31, 2011 through the year ended December 31, 2013. Although the impact of inflation
has been insignificant in recent years, it continues to be a factor in the U.S. economy and we do experience inflationary
pressure on the costs of oilfield services and equipment as drilling activity increases in the areas in which we operate.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in "—
Obligations and commitments."
72
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative
information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse
changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future
losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive
instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure. Due to the inherent volatility in oil and natural gas prices, we use commodity
derivatives, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our
anticipated oil and natural gas production. By removing a majority of the price volatility associated with future production, we
expect to reduce, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in
commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the gains and losses on open
positions are reflected in earnings. At each period end, we estimate the fair value of our commodity derivatives using an
independent third-party valuation and recognize the associated gain or loss in our consolidated statements of operations
included elsewhere in this Annual Report.
Our hedged positions as of December 31, 2013 are as follows:
Year
2014
Year
2015
Year
2016
Year
2017
Year
2018
Total
Oil(1)
Total volume hedged with ceiling price (Bbl) .......
Weighted average ceiling price ($/Bbl) .................
Total volume hedged with floor price (Bbl) ..........
Weighted average floor price ($/Bbl).....................
5,103,496
6,557,020
1,860,000
—
— 13,520,516
$
100.01
$
95.40
$
91.37
5,643,496
7,013,020
1,860,000
$
87.97
$
79.50
$
80.00
$
$
— $
— $
96.59
—
— 14,516,516
— $
— $
82.86
Natural gas(2)
Total volume hedged with ceiling price (MMBtu)
Weighted average ceiling price ($/MMBtu) ..........
Total volume hedged with floor price (MMBtu) ...
Weighted average floor price ($/MMBtu) .............
9,600,000
8,160,000
—
—
— 17,760,000
$
5.50
$
6.00
9,600,000
8,160,000
$
3.00
$
3.00
$
$
— $
— $
— $
5.73
—
—
— 17,760,000
— $
— $
— $
3.00
Oil basis swaps
Total volume hedged (Bbl) ....................................
Weighted average price ($/Bbl)(3) ..........................
Total volume hedged (Bbl) ....................................
Weighted average price ($/Bbl)(4) ..........................
_______________________________________________________________________________
2,252,000
1,840,000
3,650,000
(1.04) $
(2.85) $
—
$
$
— $
—
—
— 2,252,000
— $
— $
— $
(1.04)
3,660,000
3,650,000
1,810,000
14,610,000
(2.85) $
(2.85) $
(2.85) $
(2.85) $
(2.85)
(1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the
NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. Weighted
average prices include the West Texas Intermediate Argus Midland and the West Texas Intermediate Argus Cushing
basis swaps.
(2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation
period.
(3) The associated oil basis swap is settled on the differential between the West Texas Intermediate Argus Midland and the
West Texas Intermediate Argus Cushing index oil prices.
(4) The associated oil basis swap is settled on the differential between the Light Louisiana Sweet Argus and the Brent
International Petroleum Exchange index oil prices.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant
price indices. As of December 31, 2013, a 10% change in the forward curves associated with our commodity derivatives would
have changed our net positions to the following amounts:
(in thousands)
Commodity derivatives .....................................................................................................................
10% Increase 10% Decrease
$
959
$
153,420
73
As of December 31, 2013 and 2012, the fair values of our open derivatives contracts were assets of approximately
$82.1 million and $2.1 million, respectively. Refer to Notes G and H of our audited consolidated financial statements included
elsewhere in this Annual Report for additional disclosures regarding our derivatives.
Interest rate risk. Our Senior Secured Credit Facility bears interest at a floating rate, and as of December 31, 2013,
we had no indebtedness outstanding on our Senior Secured Credit Facility. Our 2019 and 2022 senior unsecured notes bear
fixed interest rates and we had $550.0 million (excluding the remaining premium of $1.5 million) and $500.0 million
outstanding, respectively, as of December 31, 2013, as shown in the table below.
Expected maturity date
(in millions except for interest rates)
2013
2014
2015
2016
2017
Thereafter
Total
2019 senior unsecured notes - fixed rate ......
Average interest rate .....................................
2022 senior unsecured notes - fixed rate ......
Average interest rate .....................................
Senior Secured Credit Facility - variable
rate ................................................................
Average interest rate .....................................
$ — $ — $ — $ — $ — $ 550.0
$ 550.0
—%
—%
—%
—%
—%
9.5%
9.5%
$ — $ — $ — $ — $ — $ 500.0
$ 500.0
—%
—%
—%
—%
—% 7.375% 7.375%
$ — $ — $ — $ — $ — $ — $ —
—%
—%
—%
—%
—%
—%
—%
Refer to Note O.1 of our audited consolidated financial statements included elsewhere in this Annual Report for
discussion of our issuance in January 2014 of $450.0 million in aggregate principal amount of 5 5/8% senior notes due 2022.
Through interest rate derivatives, we have attempted to mitigate our exposure to changes in interest rates. In prior
years, we have entered into various fixed interest rate swaps and a cap agreement which hedge our exposure to interest rate
variations on our Senior Secured Credit Facility. During 2013, we had one interest rate swap and one interest rate cap
outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their
expiration in September 2013.
Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from
derivatives ($95.5 million as of December 31, 2013), joint interest receivables ($16.6 million as of December 31, 2013) and the
receivables from the sale of our oil and natural gas production ($57.6 million as of December 31, 2013), which we market to
energy marketing companies and refineries.
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant
customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their
obligations to us or their insolvency or liquidation may adversely affect our financial results.
We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of
our derivative counterparties, who are each lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements
provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a
counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party
against all derivative asset receivables from the defaulting party.
Refer to Note I of our audited consolidated financial statements included elsewhere in this Annual Report for
additional disclosures regarding credit risk, including from related parties.
74
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements and supplementary financial data are included in this Annual Report beginning
on page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have
evaluated, under the supervision and with the participation of our management, including our principal executive officer and
principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our
disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed
by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our
principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the
SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our
disclosure controls and procedures were effective as of December 31, 2013 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting. There have been no changes in our internal controls over
financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have
materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
75
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over
financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the
Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with
generally accepted accounting principles.
As of December 31, 2013, management assessed the effectiveness of the Company’s internal control over financial
reporting based on the criteria for effective internal control over financial reporting established in the 1992 “Internal Control -
Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this
assessment and those criteria, management determined that the Company maintained effective internal control over financial
reporting as of December 31, 2013.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial
statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the
Company’s internal control over financial reporting as of December 31, 2013. The report, which expresses an unqualified
opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, is included in
this Item under the heading “Report of Independent Registered Public Accounting Firm.”
76
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Laredo Petroleum, Inc.
We have audited the internal control over financial reporting of Laredo Petroleum, Inc. (formerly known as Laredo Petroleum
Holdings, Inc.) (a Delaware corporation) and subsidiary (formerly subsidiaries) (the “Company”) as of December 31, 2013,
based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to
express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated financial statements of the Company as of and for the year ended December 31, 2013, and our report dated
February 27, 2014 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 27, 2014
77
Item 9B. Other Information
None.
78
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our Code of Conduct and Business Ethics, Code of Ethics For Senior Financial Officers and
Corporate Governance Guidelines for our principal executive officer and principal financial and accounting officer are
described in "Item 1. Business" in this Annual Report. Pursuant to paragraph 3 of General Instruction G to Form 10-K, we
incorporate by reference into this Item 10 the information to be disclosed in our definitive proxy statement, which is to be filed
pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.
Item 11. Executive Compensation
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 11 the
information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC
within 120 days after the close of the year ended December 31, 2013.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 12 the
information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC
within 120 days after the close of the year ended December 31, 2013.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 13 the
information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC
within 120 days after the close of the year ended December 31, 2013.
Item 14. Principal Accounting Fees and Services
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 14 the
information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC
within 120 days after the close of the year ended December 31, 2013.
79
Part IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these
statements and accompanying footnotes, see "Index to Consolidated Financial Statements" on page F-1 of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for
therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Exhibit Number
2.1
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
Description
Agreement and Plan of Merger by and between Laredo Petroleum, LLC and Laredo Petroleum Holdings, Inc.,
dated as of December 19, 2011 (incorporated by reference to Exhibit 2.1 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on December 22, 2011).
Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by
reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22,
2011).
Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1
of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2
of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration
Statement on Form 8-A12B/A (File No. 001-35380) filed on January 7, 2014).
Indenture, dated as of January 20, 2011, among Laredo Petroleum, Inc., the several guarantors named therein,
and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo's
Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
Supplemental Indenture, dated as of July 20, 2011, among Laredo Petroleum, Inc., Laredo Petroleum—
Dallas, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National Association, as
trustee (incorporated by reference to Exhibit 4.3 of Laredo's Registration Statement on Form S-1 (File
No. 333-176439) filed on August 24, 2011).
Second Supplemental Indenture, dated as of December 19, 2011, among Laredo Petroleum, Inc., Laredo
Petroleum Holdings, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National
Association, as trustee (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K
(File No. 001-35380) filed on December 22, 2011).
Third Supplemental Indenture, dated as of December 19, 2011, among Laredo Petroleum, Inc., Laredo
Petroleum Holdings, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National
Association, as trustee (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K
(File No. 001-35380) filed on December 22, 2011).
Fourth Supplemental Indenture, dated as of December 31, 2013, among the Laredo Petroleum, Inc., Laredo
Midstream Services, LLC, and Wells Fargo Bank, National Association, as trustee under the 2011 Indenture
(incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed
on January 6, 2014).
80
Exhibit Number
Description
4.7
4.8
4.9
4.10
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the several guarantors named therein
and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's
Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).
Supplemental Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the several guarantors
named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit
4.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).
Second Supplemental Indenture, dated as of December 31, 2013, among Laredo Petroleum Holdings, Inc.,
Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and Wells Fargo Bank, National Association, as
trustee under the 2012 Indenture (incorporated by reference to Exhibit 4.2 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on January 6, 2014).
Indenture, dated as of January 23, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC and
Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's
Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).
Third Amended and Restated Credit Agreement, dated as of July 1, 2011, among Laredo Petroleum, Inc.,
Wells Fargo Bank, N.A., as Administrative Agent, Bank of America, N.A. and JPMorgan Chase Bank, N.A.,
as Co-Syndication Agents, Societe Generale, Union Bank, N.A. and BMO Harris Financing, Inc., as Co-
Documentation Agents, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and
J.P. Morgan Securities LLC, as Joint Lead Arrangers and the financial institutions listed on Schedule I thereto
(incorporated by reference to Exhibit 10.1 of Laredo's Registration Statement on Form S-1 (File
No. 333-176439) filed on August 24, 2011).
First Amendment to Third Amended and Restated Credit Agreement, dated as of October 11, 2011, among
Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo
Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.4 of Laredo's Registration
Statement on Form S-1A (File No. 333-176439) filed on November 14, 2011).
Limited Consent and Second Amendment to Third Amended and Restated Credit Agreement, dated as of
November 23, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the
guarantors signatories thereto and the banks signatories thereto (incorporated by reference to Exhibit 10.3 of
Laredo's Registration Statement on From S-4/A (File No. 333-173984-05) filed on December 12, 2011).
Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 24, 2012, among
Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo
Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on April 25, 2012).
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of April 27, 2012, among
Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo
Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on April 30, 2012).
Fifth Amendment to Third Amended and Restated Credit Facility, dated as of November 7, 2012, among
Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and
the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Quartlery Report on Form
10-Q (File No. 001-35380) filed on November 9, 2012).
Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of May 29, 2013, among
Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and
the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-
K (File No. 001-35380) filed on May 30, 2013).
Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of November 4, 2013,
among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory
thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Quarterly
Report on Form 10-Q (File No. 001-35380) filed on November 7, 2013).
Fourth Amended and Restated Credit Agreement, dated as of December 31, 2013, among Laredo Petroleum,
Inc., as borrower, Wells Fargo Bank, National Association as administrative agent, and the other financial
institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form
8-K (File No. 001-35380) filed on January 6, 2014).
10.10
First Amendment to Fourth Amended and Restated Credit Agreement, dated as of January 31, 2014, among
Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC
and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on February 4, 2014).
81
Exhibit Number
10.11
10.12
10.13
10.14
10.15#
10.16#
10.17#
10.18#
10.19#
10.20#
10.21
Description
Purchase and Sale Agreement, dated May 20, 2013, by and between Laredo Petroleum, Inc., Laredo
Petroleum Texas, LLC, Laredo Gas Services, LLC and EnerVest Energy Institutional Fund XII-WIB, L.P.,
EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest
Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy
Institutional Fund XIII-WIC, L.P. and EnerVest Operating, L.L.C. (incorporated by reference to Exhibit 10.1
of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on August 1, 2013).
Contribution Agreement, dated as of June 15, 2011, by and among Broad Oak Energy, Inc., Warburg Pincus
Private Equity IX, L.P., the other persons listed as Contributors on the signature pages thereto and Laredo
Petroleum, LLC (incorporated by reference to Exhibit 10.2 of Laredo's Registration Statement on Form S-1
(File No. 333-176439) filed on August 24, 2011).
Stock Purchase and Sale Agreement, dated as of June 15, 2011, by and among Laredo Petroleum, Inc. and the
individuals listed as Sellers on the signature pages thereto (incorporated by reference to Exhibit 10.3 of
Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
Form of Registration Rights Agreement dated December 20, 2011 among Laredo Petroleum Holdings, Inc.
and the signatories thereto (incorporated by reference to Exhibit 10.5 of Laredo's Current Report on Form 8-K
(File No. 001-35380) filed on December 22, 2011).
Form of Indemnification Agreement between Laredo Petroleum Holdings, Inc. and each of the officers and
directors thereof (incorporated by reference to Exhibit 10.6 of Laredo's Current Report on Form 8-K (File
No. 001-35380) filed on December 22, 2011).
Laredo Petroleum Holdings, Inc. 2011 Omnibus Equity Incentive Plan (incorporated by reference to
Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on February 9, 2012).
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Quarterly Report
on Form 10-Q (File No. 001-35380) filed on August 9, 2012).
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on
Form 8-K (File No. 001-35380) filed on February 9, 2012).
Form of Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.3 of Laredo's
Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).
Laredo Petroleum Holdings, Inc. Change in Control Executive Severance Plan Certificate (incorporated by
reference to Exhibit 10.7 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on
November 14, 2011).
10.22#* Form of 2013 Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.16 of
Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on March 12, 2013.
10.23*
10.24
Non-Exclusive Aircraft Lease Agreement, dated January 1, 2013 between Lariat Ranch, LLC and Laredo
Petroleum, Inc (incorporated by reference to Exhibit 10.17 of Laredo's Annual Report on Form 10-K (file No.
001-35380) filed on March 12, 2013.
Registration Rights Agreement, dated as of January 23, 2014, among Laredo Petroleum, Inc., Laredo
Midstream Services, LLC and the initial purchasers (incorporated by reference to Exhibit 10.1 of Laredo's
Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).
21.1*
List of Subsidiaries of Laredo Petroleum, Inc.
23.1*
Consent of Grant Thornton LLP.
23.2*
Consent of Ryder Scott Company, L.P.
31.1*
31.2*
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act
of 1934.
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act
of 1934.
82
Exhibit Number
Description
32.1** Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
Summary Report of Ryder Scott Company, L.P.
101.INS*
XBRL Instance Document.
101.CAL*
XBRL Schema Document.
101.SCH*
XBRL Calculation Linkbase Document.
101.DEF*
XBRL Definition Linkbase Document.
101.LAB*
XBRL Labels Linkbase Document.
101.PRE*
XBRL Presentation Linkbase Document.
___________________________________________________________________________
* Filed herewith.
** Furnished herewith.
# Management contract or compensatory plan or arrangement.
83
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date: February 27, 2014
LAREDO PETROLEUM, INC.
By:
/s/ Randy A. Foutch
Randy A. Foutch
Chief Executive Officer
KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and
appoints Randy A. Foutch, Richard C. Buterbaugh and Kenneth E. Dornblaser, each of whom may act without joinder of the
other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such
person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report
on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities
and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and
every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might
or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signatures
/s/ Randy A. Foutch
Randy A. Foutch
/s/ Richard C. Buterbaugh
Richard C. Buterbaugh
/s/ Jay P. Still
Jay P. Still
/s/ Peter R. Kagan
Peter R. Kagan
/s/ James R. Levy
James R. Levy
/s/ B.Z. (Bill) Parker
B.Z. (Bill) Parker
/s/ Pamela S. Pierce
Pamela S. Pierce
/s/ Ambassador Francis Rooney
Ambassador Francis Rooney
/s/ Dr. Myles W. Soggins
Dr. Myles W. Scoggins
/s/ Edmund P. Segner, III
Edmund P. Segner, III
/s/ Donald D. Wolf
Donald D. Wolf
Title
Chairman and Chief Executive Officer
(principal executive officer)
Executive Vice President and Chief
Financial Officer (principal financial
and accounting officer)
Director, President and Chief
Operating Officer
Director
Director
Director
Director
Director
Director
Director
Director
84
Date
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
2/27/2014
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Financial Statements of Laredo Petroleum, Inc.:
Report of Independent Registered Public Accounting Firm .............................................................................................
Consolidated balance sheets as of December 31, 2013 and 2012.....................................................................................
Consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 ....................................
Consolidated statements of stockholders' equity for the years ended December 31, 2013, 2012 and 2011.....................
Consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011....................................
Notes to the consolidated financial statements .................................................................................................................
Supplemental oil and natural gas disclosures (Unaudited) ...............................................................................................
Supplemental quarterly financial data (Unaudited) ..........................................................................................................
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-44
F-49
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Laredo Petroleum, Inc.
We have audited the accompanying consolidated balance sheets of Laredo Petroleum, Inc. (formerly known as Laredo
Petroleum Holdings, Inc.) (a Delaware corporation) and subsidiary (formerly subsidiaries) (the “Company”) as of
December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders' equity, and cash flows for
each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Laredo Petroleum, Inc. (formerly known as Laredo Petroleum Holdings, Inc.) and subsidiary (formerly subsidiaries)
as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the Company's internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report dated February 27, 2014, expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 27, 2014
F-2
Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
December 31,
2013
2012
Assets
Current assets:
Cash and cash equivalents .......................................................................................................................................... $
198,153
$
Accounts receivable, net .............................................................................................................................................
Derivatives ..................................................................................................................................................................
Deferred income taxes ................................................................................................................................................
Other current assets.....................................................................................................................................................
Total current assets................................................................................................................................................
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties .....................................................................................................................................................
Unproved properties not being amortized................................................................................................................
Pipeline and gathering assets ......................................................................................................................................
Other fixed assets........................................................................................................................................................
Total property and equipment...............................................................................................................................
Less accumulated depletion, depreciation, amortization and impairment..................................................................
Net property and equipment..................................................................................................................................
Deferred income taxes ...................................................................................................................................................
Derivatives .....................................................................................................................................................................
Deferred loan costs, net..................................................................................................................................................
Investment in equity method investee............................................................................................................................
Other assets, net .............................................................................................................................................................
77,318
15,806
3,634
12,698
307,609
3,276,578
208,085
44,255
40,281
3,569,199
(1,364,875)
2,204,324
—
79,726
25,933
5,913
255
33,224
83,840
4,644
12,713
3,016
137,437
2,993,266
159,946
74,877
25,599
3,253,688
(1,139,797)
2,113,891
49,916
2,058
29,444
—
5,558
Total assets...................................................................................................................................................... $
2,623,760
$
2,338,304
Liabilities and stockholders' equity
Current liabilities:
Accounts payable ........................................................................................................................................................ $
16,002
$
Accrued payable - affiliates ........................................................................................................................................
Undistributed revenue and royalties ...........................................................................................................................
Accrued capital expenditures......................................................................................................................................
Accrued compensation and benefits ...........................................................................................................................
Derivatives ..................................................................................................................................................................
Other current liabilities ...............................................................................................................................................
Total current liabilities..........................................................................................................................................
Long-term debt...............................................................................................................................................................
Derivatives .....................................................................................................................................................................
Deferred income taxes ...................................................................................................................................................
Asset retirement obligations ..........................................................................................................................................
Other noncurrent liabilities ............................................................................................................................................
3,489
35,124
116,328
16,711
10,795
55,520
253,969
1,051,538
2,680
16,293
21,478
5,546
48,672
—
36,065
121,612
10,318
1,325
44,076
262,068
1,216,760
3,260
—
21,120
3,373
Total liabilities ......................................................................................................................................................
1,351,504
1,506,581
Commitments and contingencies ...................................................................................................................................
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2013 and 2012...
—
—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 142,671,436 and 128,298,559 issued, net of
treasury, at December 31, 2013 and 2012, respectively .............................................................................................
Additional paid-in capital ...........................................................................................................................................
Accumulated deficit ....................................................................................................................................................
Treasury stock, at cost, zero and 7,609 common shares at December 31, 2013 and 2012, respectively....................
1,427
1,283,809
(12,980)
—
Total stockholders' equity .....................................................................................................................................
1,272,256
1,283
961,424
(130,980)
(4)
831,723
Total liabilities and stockholders' equity......................................................................................................... $
2,623,760
$
2,338,304
The accompanying notes are an integral part of these consolidated financial statements.
F-3
Laredo Petroleum, Inc.
Consolidated statements of operations
(in thousands, except per share data)
Revenues:
Oil and natural gas sales .................................................................................................................... $
664,844
$
583,569
$
506,255
For the years ended December 31,
2013
2012
2011
Transportation and treating ................................................................................................................
Total revenues...........................................................................................................................
Costs and expenses:
Lease operating expenses...................................................................................................................
Production and ad valorem taxes .......................................................................................................
Transportation and treating ................................................................................................................
Transportation and treating - affiliates...............................................................................................
Drilling and production......................................................................................................................
General and administrative (including non-cash stock-based compensation of $21,433, $10,056
and $6,111 for the years ended December 31, 2013, 2012 and 2011, respectively)..........................
Accretion of asset retirement obligations ..........................................................................................
Depletion, depreciation and amortization ..........................................................................................
Total costs and expenses...........................................................................................................
Operating income..................................................................................................................................
Non-operating income (expense):
Gain (loss) on derivatives:
413
665,257
79,136
42,396
680
891
2,688
89,696
1,475
233,944
450,906
214,351
Commodity derivatives, net ............................................................................................................
79,902
Interest rate derivatives, net ............................................................................................................
Income from equity method investee.................................................................................................
(24)
29
325
583,894
67,325
37,637
162
—
2,452
62,106
1,200
241,072
411,954
171,940
8,800
(412)
—
Interest expense..................................................................................................................................
(100,327)
(85,572)
Interest and other income...................................................................................................................
Write-off of deferred loan costs.........................................................................................................
Loss on disposal of assets, net ...........................................................................................................
Non-operating expense, net ......................................................................................................
Income from continuing operations before income taxes..................................................................
Income tax expense:
Deferred .............................................................................................................................................
Total income tax expense..........................................................................................................
Income from continuing operations ......................................................................................................
Income (loss) from discontinued operations, net of tax........................................................................
163
(1,502)
(1,508)
(23,267)
191,084
(74,507)
(74,507)
116,577
1,423
59
—
(51)
(77,176)
94,764
(33,003)
(33,003)
61,761
(107)
92
506,347
43,306
31,982
65
—
2,675
51,064
616
174,119
303,827
202,520
21,047
(1,311)
—
(50,580)
108
(6,195)
(1)
(36,932)
165,588
(59,612)
(59,612)
105,976
(422)
Net income ............................................................................................................................................ $
118,000
$
61,654
$
105,554
Net income per common share:
Basic:
Income from continuing operations ................................................................................................ $
Income (loss) from discontinued operations, net of tax..................................................................
Net income per share ................................................................................................................... $
Diluted:
Income from continuing operations ................................................................................................ $
Income (loss) from discontinued operations, net of tax..................................................................
Net income per share ................................................................................................................... $
Weighted average common shares outstanding:
0.88
0.01
0.89
0.87
0.01
0.88
$
$
$
$
0.49
—
0.49
0.48
—
0.48
$
$
$
$
0.99
(0.01)
0.98
0.98
—
0.98
Basic...................................................................................................................................................
Diluted................................................................................................................................................
132,490
134,378
126,957
128,171
107,187
108,099
The accompanying notes are an integral part of these consolidated financial statements.
F-4
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Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
For the years ended December 31,
2012
2011
2013
Cash flows from operating activities:
Net income ................................................................................................................................................ $
Adjustments to reconcile net income to net cash provided by operating activities:
118,000
$
61,654
$
105,554
Deferred income tax expense ..............................................................................................................
Depletion, depreciation and amortization ...........................................................................................
Bad debt expense.................................................................................................................................
Impairment expense ............................................................................................................................
Non-cash stock-based compensation...................................................................................................
Accretion of asset retirement obligations............................................................................................
Mark-to-market on derivatives:
Gain on derivatives, net....................................................................................................................
Cash settlements received (paid) for matured derivatives, net.........................................................
Cash settlements received for early terminations and modifications of derivatives, net .................
Change in net present value of deferred premiums paid for derivatives.............................................
Cash premiums paid for derivatives....................................................................................................
Amortization of deferred loan costs ....................................................................................................
Write-off of deferred loan costs...........................................................................................................
Amortization of October 2011 Notes premium...................................................................................
Amortization of other assets................................................................................................................
Loss on disposal of assets, net.............................................................................................................
Equity method investee income ..........................................................................................................
Cash settlement of performance unit awards ......................................................................................
(Increase) decrease in accounts receivable..........................................................................................
(Increase) decrease in other assets.......................................................................................................
Increase (decrease) in accounts payable..............................................................................................
Increase (decrease) in undistributed revenues and royalties ...............................................................
Increase (decrease) in accrued compensation and benefits .................................................................
Increase (decrease) in other accrued liabilities....................................................................................
Increase (decrease) in other noncurrent liabilities...............................................................................
Increase (decrease) in fair value of performance unit awards.............................................................
Net cash provided by operating activities .....................................................................................
Cash flows from investing activities:
Capital expenditures:
Acquisitions of oil and natural gas properties ........................................................................................
Investment in equity method investee ....................................................................................................
Oil and natural gas properties.................................................................................................................
Pipeline and gathering assets..................................................................................................................
Other fixed assets ...................................................................................................................................
Proceeds from dispositions of capital assets, net of costs .........................................................................
Net cash used in investing activities..............................................................................................
Cash flows from financing activities:
Broad Oak transaction ...............................................................................................................................
Borrowings on revolving credit facilities..................................................................................................
Payments on revolving credit facilities .....................................................................................................
Payments on term loan ..............................................................................................................................
Issuance of 2019 Notes..............................................................................................................................
Issuance of 2022 Notes..............................................................................................................................
Proceeds from issuance of common stock, net of offering costs ..............................................................
Purchase of equity interests and units, net ................................................................................................
Proceeds from exercise of employee stock options...................................................................................
Purchase of treasury stock.........................................................................................................................
Payments for loan costs.............................................................................................................................
Net cash provided by financing activities .....................................................................................
Net increase (decrease) in cash and cash equivalents ..................................................................................
Cash and cash equivalents, beginning of period ..........................................................................................
Cash and cash equivalents, end of period..................................................................................................... $
75,288
234,571
653
—
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3,745
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499
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450,128
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—
230,000
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—
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4,816
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98
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569,197
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16,180
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—
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790,100
(1,096,700)
(100,000)
552,000
—
319,378
(164)
—
(3)
(23,170)
359,478
(3,233)
31,235
28,002
$
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
A—Organization
The Company (defined below) is an independent energy company focused on the exploration, development and
acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, the Company
sold its properties in the Mid-Continent region of the United States (as further described below).
Laredo Petroleum, Inc. (“Laredo”), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the
laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public
offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited
liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a
holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum,
Inc. ("Laredo Inc"), a Delaware corporation, and Laredo Inc’s subsidiaries, Laredo Petroleum Texas, LLC (“Laredo Texas”), a
Texas limited liability company, Laredo Gas Services, LLC (“Laredo Gas”), a Delaware limited liability company, and Laredo
Petroleum—Dallas, Inc. (“Laredo Dallas”), a Delaware corporation.
Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate
structure. Two of Laredo Inc's subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole
remaining wholly-owned subsidiary of Laredo Inc, Laredo Gas, changed its name to Laredo Midstream Services, LLC
("Laredo Midstream" or "Guarantor"). Laredo Inc merged with and into Laredo with Laredo surviving and changing its name to
‘‘Laredo Petroleum, Inc.’’(the events described in this paragraph collectively, the "Internal Consolidation").
On July 1, 2011, Laredo LLC and Laredo Inc completed the acquisition of Broad Oak Energy, Inc. ("Broad Oak"), a
Delaware corporation, for a combination of equity and cash. Prior to the acquisition, Broad Oak was owned by its management
and Warburg Pincus Private Equity IX, L.P. ("Warburg Pincus IX"). On July 19, 2011, Broad Oak's name was changed to
Laredo Petroleum—Dallas, Inc.
On December 19, 2011, immediately prior to the IPO, Laredo LLC merged with and into Laredo, with Laredo being
the surviving entity. Warburg Pincus IX and other affiliates of Warburg Pincus LLC ("Warburg Pincus") were majority owners
of Laredo LLC and until November 25, 2013 were of Laredo. The preferred units and certain series of restricted units of
Laredo LLC were exchanged into shares of common stock of Laredo based on the pre-offering equity value of such units in the
Corporate Reorganization. The common stock has one vote per share and a par value of $0.01 per share.
In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2013, refers to
Laredo and Laredo Midstream collectively; (ii) when used for historical periods from December 19, 2011 to December 30,
2013, refers to Laredo and its subsidiaries, collectively; and (iii) when used for historical periods prior to December 19, 2011
refers to Laredo LLC, Laredo Inc and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars
and percentages presented in these consolidated financial statements and the related notes are rounded and therefore
approximate.
On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's
management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of
Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price
to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27,
2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option
to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net
proceeds of $298.1 million, after underwriting discounts, commissions, and offering expenses as a result of the Follow-on
Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the
Selling Stockholders.
B—Basis of presentation and significant accounting policies
1. Basis of presentation
The accompanying consolidated financial statements were derived from the historical accounting records of the
Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The
Broad Oak acquisition discussed in Note A was accounted for in a manner similar to a pooling of interests. The historical
financial statements present the assets and liabilities of Laredo and its subsidiaries and Broad Oak at historical carrying values
and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account
balances have been eliminated in the consolidation of accounts. The accompanying consolidated financial statements have been
prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The
F-7
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Company operates oil and natural gas properties as one business segment, which explores, develops and produces oil and
natural gas. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.
2. Use of estimates in the preparation of consolidated financial statements
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires
management of the Company to make estimates and assumptions about future events. These estimates and the underlying
assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management
believes these estimates are reasonable, actual results could differ from these estimates.
Significant estimates include, but are not limited to, (i) estimates of the Company’s reserves of oil and natural gas, (ii)
future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement
obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed
in an acquisition and (viii) fair values of commodity derivatives, interest rate derivatives, commodity deferred premiums and
performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market
participants would use. These estimates and assumptions are based on management’s best judgment. Management evaluates its
estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic
environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and
volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions.
Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects
cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates
resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
3. Reclassifications
Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2013
presentation. These reclassifications had no impact to previously reported net income or losses, total stockholders' equity or
cash flows. See Note C for a discussion regarding discontinued operations.
4. Cash and cash equivalents
The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be
federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any
significant credit risk on such accounts. The Company defines cash and cash equivalents to include cash on hand, cash in bank
accounts and highly liquid investments with original maturities of three months or less.
5. Accounts receivable
The Company sells oil and natural gas to various customers and participates with other parties in the drilling,
completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these
operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers
less an allowance for doubtful accounts.
Amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable
allowances based on management's assessment of the creditworthiness of the joint interest owners and, as the operator in the
majority of its wells, the ability to realize the receivables through netting of anticipated future production revenues. The
Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In
establishing the required allowance, management considers historical losses, current receivables aging, and existing industry
and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances greater than 90 days
and over a specified amount are reviewed individually for collectability. Account balances are charged off against the
allowance after all means of collection have been exhausted and the potential for recovery is remote.
F-8
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Accounts receivable consist of the following components as of December 31:
(in thousands)
2013
2012
Oil and natural gas sales....................................................................................................................
Joint operations, net(1) .......................................................................................................................
Other..................................................................................................................................................
Total................................................................................................................................................
$
57,647
$
16,629
3,042
48,445
30,925
4,470
$
77,318
$
83,840
______________________________________________________________________________
(1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and
$0.1 million as of December 31, 2013 and 2012, respectively.
6. Derivatives
The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a
significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate,
the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are
primarily in the form of collars, swaps, puts and basis swaps. In addition, the Company enters into derivative contracts in the
form of interest rate derivatives to minimize the effects of fluctuations in interest rates.
Derivatives are recorded at fair value and are included on the consolidated balance sheets as assets or liabilities. The
Company netted the fair value of derivatives by counterparty in the accompanying consolidated balance sheets where the right
of offset exists. The Company determines the fair value of its derivatives utilizing pricing models for substantially similar
instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a
compilation of data gathered from third parties.
The Company’s derivatives were not designated as hedges for accounting purposes for any of the periods presented.
Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change.
Gains and losses on derivatives are included in cash flows from operating activities (see Note G).
7. Other current liabilities
Other current liabilities consist of the following components as of December 31:
(in thousands)
Accrued interest payable ...................................................................................................................
Lease operating expense payable ......................................................................................................
Prepaid drilling liability ....................................................................................................................
Production taxes payable ..................................................................................................................
Current portion of asset retirement obligations.................................................................................
Other accrued liabilities ....................................................................................................................
Total other current liabilities...........................................................................................................
$
$
2013
2012
25,885
10,637
1,393
1,303
265
16,037
55,520
$
$
26,106
9,766
2,916
2,121
385
2,782
44,076
8. Oil and natural gas properties
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all
acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil
and natural gas are capitalized and amortized on a composite units of production method based on proved oil and natural gas
reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals and other costs related to such activities. Costs, including related employee costs, associated with production and
general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being
amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.
The Company computes the provision for depletion of oil and natural gas properties using the units of production
method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are
excluded from the amortization base until the properties associated with these costs are evaluated. Approximately $208.1
million and $159.9 million of such costs were excluded from the amortization base as of December 31, 2013 and 2012,
F-9
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
respectively. The amortization base includes estimated future development costs and dismantlement, restoration and
abandonment costs, net of estimated salvage values. Total accumulated depletion for oil and natural gas properties was $1.3
billion and $1.1 billion for the years ended December 31, 2013 and 2012, respectively. Depletion expense for oil and natural
gas properties was $228.0 million, $237.1 million and $171.5 million for the years ended December 31, 2013, 2012 and 2011,
respectively. There were no impairments recorded for the years ended December 31, 2013, 2012 and 2011. Depletion per
barrel of oil equivalent for the Company's oil and natural gas properties was $20.34, $20.98 and $19.82 for the years ended
December 31, 2013, 2012 and 2011, respectively.
The Company excludes the costs directly associated with acquisition and evaluation of unproved properties from the
depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. All items classified
as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment
includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical
evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if
proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs
incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and
are then subject to amortization.
The full cost ceiling is based principally on the estimated future net cash flows from oil and natural gas properties
discounted at 10%. Full cost companies are required to use the unweighted arithmetic average first-day-of-the-month price for
each month within the 12-month period prior to the end of the reporting period, unless prices were defined by contractual
arrangements, to calculate the discounted future revenues. In the event the unamortized cost of oil and natural gas properties
being amortized exceeds the full cost ceiling, as defined by the Securities and Exchange Commission ("SEC"), the excess is
charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not
reversible.
As of December 31, 2013, the full cost ceiling value of the Company's reserves was calculated based on the
unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $3.57 per MMBtu
for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted
arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $93.52 per barrel for oil,
adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net
book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013. Changes in
production rates, levels of reserves, future development costs, and other factors will determine the Company's actual full cost
ceiling test calculation and impairment analysis in future periods.
As of December 31, 2012, the full cost ceiling value of the Company's reserves was calculated based on the
unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $2.63 per MMBtu
for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted
arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $91.21 per barrel for oil,
adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net
book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.
As of December 31, 2011, the full cost ceiling value of the Company's reserves was calculated based on the
unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2011 of $3.99 per MMBtu
for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted
arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2011 of $92.71 per barrel for oil,
adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net
book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2011.
9. Pipeline and gathering assets
Pipeline and gathering assets are recorded at cost, net of accumulated depreciation, and consist of gathering assets and
related equipment. Depreciation of assets is provided using the shorter of the lease term or the straight-line method based on
estimated useful lives of 20 years, as applicable. Expenditures for major renewals or betterments, which extend the useful lives
of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated
depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income
(expense)" in the consolidated statements of operations. Depreciation expense from continuing operations for pipeline and
gathering assets was $1.5 million, $0.8 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011,
respectively.
F-10
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Pipeline and gathering assets consist of the following as of December 31:
(in thousands)
2013
2012
Pipeline and gathering assets ............................................................................................................
Less accumulated depreciation .........................................................................................................
Total, net .........................................................................................................................................
$
$
44,255
2,757
41,498
$
$
74,877
9,585
65,292
10. Other fixed assets
Other fixed assets are recorded at cost net of accumulated depreciation and amortization. Land is recorded at cost and
is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the shorter of the lease term
or the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are
capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases.
Expenditures for major renewals or betterments, which extend the useful lives of existing fixed assets, are capitalized and
depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from
the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of
operations. Depreciation and amortization expense from continuing operations for other fixed assets was $4.4 million, $3.1
million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Other fixed assets consist of the following as of December 31:
(in thousands)
2013
2012
Computer hardware and software .....................................................................................................
Drilling service assets .......................................................................................................................
Aircraft ..............................................................................................................................................
Vehicles.............................................................................................................................................
Leasehold improvements ..................................................................................................................
Furniture and fixtures........................................................................................................................
Production equipment .......................................................................................................................
Other..................................................................................................................................................
Depreciable total .............................................................................................................................
Less accumulated depreciation and amortization .............................................................................
Depreciable total, net....................................................................................................................
Land ..................................................................................................................................................
Total, net ....................................................................................................................................
$
$
11,370
7,269
4,952
4,741
3,520
1,342
403
2,546
36,143
12,803
23,340
4,138
$
27,478
$
7,774
7,223
—
3,396
3,121
1,057
262
675
23,508
8,938
14,570
2,091
16,661
11. Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which
are often changing, regulate the discharge of materials into the environment and may require the Company to remove or
mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed in the period incurred. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefits are expensed in the period incurred. Liabilities for expenditures of a
non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably
estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
Management believes no materially significant liabilities of this nature existed as of December 31, 2013 or 2012.
12. Deferred loan costs
Loan origination fees, which are stated at cost, net of amortization, are amortized over the life of the respective debt
agreements utilizing the effective interest and straight-line methods. The Company capitalized $3.0 million and $10.8 million
of deferred loan costs during the year ended December 31, 2013 and 2012, respectively. The Company had total deferred loan
costs of $25.9 million and $29.4 million, net of accumulated amortization of $14.2 million and $9.2 million, as of
December 31, 2013 and 2012, respectively.
F-11
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
During the years ended December 31, 2013 and 2011, the Company wrote-off $1.5 million and $6.2 million,
respectively, in deferred loan costs as a result of the retirement of debt and changes in the borrowing base under the Senior
Secured Credit Facility (as defined in Note D). No deferred loan costs were written off in the year ended December 31, 2012.
Future amortization expense of deferred loan costs as of December 31, 2013 is as follows:
(in thousands)
2014 ..........................................................................................................................................................................
2015 ..........................................................................................................................................................................
2016 ..........................................................................................................................................................................
2017 ..........................................................................................................................................................................
2018 ..........................................................................................................................................................................
Thereafter..................................................................................................................................................................
Total........................................................................................................................................................................
$
4,258
4,320
4,386
4,457
4,252
4,260
$
25,933
13. Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets, are recognized as a liability in
the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying
amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived
asset is charged to expense through the depletion of the asset. Changes in the liability due to the passage of time are recognized
as an increase in the carrying amount of the liability and as corresponding accretion expense.
The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent
with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation
include: (i) estimated plug and abandonment cost per well based on Company experience; (ii) estimated remaining life per well
based on the reserve life per well; (iii) future inflation factors; and (iv) the Company's average credit adjusted risk free rate.
Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in
addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement, and changes in
legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair
value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.
The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering
assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement
of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the
settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering
assets in the periods in which settlement dates are reasonably determinable.
The following reconciles the Company's asset retirement obligations liability for continuing and discontinued
operations as of December 31:
(in thousands)
Liability at beginning of year............................................................................................................
Liabilities added due to acquisitions, drilling, and other ..................................................................
Accretion expense .............................................................................................................................
Liabilities settled upon plugging and abandonment .........................................................................
Liabilities removed due to the Anadarko Basin Sale ........................................................................
Revision of estimates ........................................................................................................................
Liability at end of year....................................................................................................................
14. Fair value measurements
$
2013
2012
$
21,505
2,709
1,475
(226)
(7,801)
4,081
13,074
4,233
1,200
(148)
—
3,146
$
21,743
$
21,505
The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable,
prepaid expenses, accounts payable, undistributed revenue and royalties and other accrued liabilities approximate their fair
values. See Note D for fair value disclosures related to the Company’s debt obligations. The Company carries its derivatives at
fair value. See Note G and Note H for details regarding the fair value of the Company’s derivatives.
F-12
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
15. Treasury stock
The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's
employees that arise upon the lapse of restrictions on restricted stock or for other reasons. Upon acquisition, this treasury stock
is retired.
16. Revenue recognition
Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes
revenues based on actual volumes of oil and natural gas sold to purchasers. The Company and other joint interest owners may
sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner
has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive gas
imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of
remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any
allowance from the overproduced working interest owner. During the year ended December 31, 2013, the majority of the
Company's natural gas imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined
below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013,
which increased oil and natural gas sales, was $0.03 million.
17. General and administrative expense
The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such
reimbursements as a reduction of general and administrative expenses.
The following amounts have been recorded for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Fees received for the operation of jointly-owned oil and natural gas properties ......
$
3,398
$
2,335
$
2,241
18. Compensation awards
For stock-based compensation awards, compensation expense is recognized in "General and administrative" in the
Company's consolidated statements of operations over the awards' vesting periods based on their grant date fair value. The
Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock
awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The
Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair value of the
performance unit awards. See Note E for further discussion of the restricted stock awards, restricted stock option awards and
performance unit awards.
19. Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax
rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce
deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly
basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the
deferred tax assets and adjusts the amount of such allowances, if necessary. See Note F for detail of amounts recorded in the
consolidated financial statements.
The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial
statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be
sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the
position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be
recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is
measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company
has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31,
2013, 2012 or 2011.
F-13
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
20. Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when
indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the
assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
The Company determined a lower of cost or market adjustment was not necessary for materials and supplies as of December
31, 2013 and 2012. During the year ended December 31, 2011, the Company reduced materials and supplies by $0.2 million in
order to reflect the balance at the lower of cost or market. This reduction is recorded in "Income (loss) from discontinued
operations, net of tax" in the Company's consolidated statements of operations. For the years ended December 31, 2013, 2012
and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-
lived assets.
21. Supplemental cash flow disclosure information and non-cash investing and financing information
The following table summarizes the supplemental disclosure of cash flow information for the periods presented:
(in thousands)
Cash paid for interest, net of $255, $627 and zero of capitalized interest,
respectively.................................................................................................................
For the years ended December 31,
2013
2012
2011
$
95,622
$
74,638
$
31,157
The following presents the supplemental disclosure of non-cash investing and financing information for the periods
presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Change in accrued capital expenditures .....................................................................
Capitalized asset retirement cost ................................................................................
Equity issued in connection with acquisition .............................................................
$
$
$
(5,284) $
$
6,790
$
3,029
30,590
$
25,122
7,379
$
— $
4,520
—
C—Acquisitions and divestitures
The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the
Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities
assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are
expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The
most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair
value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount.
Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future
commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of
capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of
the unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-
weighting factors.
1. 2013 acquisition
On September 6, 2013, the Company completed the acquisition of proved and unproved oil and natural gas properties
located in Glasscock County, Texas, from private parties for $36.7 million consisting of cash and Laredo's restricted common
stock, subject to customary closing adjustments. The results of operations prior to September 2013 do not include results from
this acquisition.
F-14
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following table reflects the final estimate of the fair value of the acquired assets and liabilities associated with this
acquisition as of September 6, 2013:
(in thousands)
Fair value of net assets:
Proved oil and natural gas properties(1) ..................................................................................................................
Unproved oil and natural gas properties(1) .............................................................................................................
Other assets ............................................................................................................................................................
Total assets acquired............................................................................................................................................
Liabilities assumed.................................................................................................................................................
Net assets acquired ...........................................................................................................................................
Fair value of consideration paid for net assets:
Cash consideration, net of closing adjustments .....................................................................................................
Common stock issued(2)..........................................................................................................................................
Total consideration paid for net assets.................................................................................................................
$
$
$
$
9,652
27,087
200
36,939
(200)
36,739
33,710
3,029
36,739
_____________________________________________________________________________
(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with
future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil
and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections
of future rates of production. The commodity prices utilized were based upon commodity strip prices as of September
6, 2013, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted
using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair
value hierarchy, as described in Note H.
(2) In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its
common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares are
restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair
value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per
share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64%
was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of
Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in
Note H.
2. 2013 divestiture of Dalhart Basin acreage
On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the
Dalhart Basin for $20.4 million, subject to customary closing adjustments.
3. 2013 divestiture of Anadarko assets
On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and
various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern
Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other
third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The
purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0
million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the
rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of
April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.
Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of
the Company and the Company does not have continuing involvement in the operations of these properties. The results of
operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as
discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.
F-15
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following table presents revenues and expenses of the oil and natural gas properties that are a component of the
Anadarko Basin Sale included in the accompanying consolidated statements of operations for the periods presented:
(in thousands)
Revenues ....................................................................................................................
Expenses(1) .................................................................................................................
_____________________________________________________________________________
For the years ended December 31,
$
2013
59,631
46,357
$
2012
84,616
89,602
$
2011
103,746
80,308
(1) Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and
depletion, depreciation and amortization expense.
The results of operations of the associated pipeline assets and various other associated property and equipment
("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements.
Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect
these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the
consolidated statements of operations in the line item "Loss on disposal of assets, net."
The following represents operating results from discontinued operations for the periods presented:
(in thousands)
Revenues:
For the years ended December 31,
2013
2012
2011
Transportation and treating ....................................................................................
Total revenues from discontinued operations ....................................................
$
$
4,020
4,020
$
4,186
4,186
3,923
3,923
Cost and expenses:
Transportation and treating ....................................................................................
Drilling and production ..........................................................................................
Depletion, depreciation and amortization ..............................................................
Impairment expense ...............................................................................................
Total costs and expenses from discontinued operations ....................................
Non-operating expense, net .......................................................................................
Income (loss) from discontinued operations before income tax................................
Income tax (expense) benefit .....................................................................................
Income (loss) from discontinued operations..............................................................
$
1,207
(18)
627
—
1,816
—
2,204
(781)
1,423
$
1,306
463
2,577
—
4,346
(1)
(161)
54
(107) $
912
1,142
2,247
243
4,544
(39)
(660)
238
(422)
4. 2012 acquisition
On July 12, 2012, the Company completed the acquisition of additional working interest in certain oil and natural gas
properties located in Glasscock County, Texas, for a contract price of $20.5 million from a private company, net of closing
purchase price adjustments. The results of operations prior to July 2012 do not include results from this acquisition.
F-16
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following table reflects the estimated fair value of the acquired assets and liabilities associated with this
acquisition at July 12, 2012:
(in thousands)
Fair value of net assets:
Proved oil and natural gas properties(1) ..................................................................................................................
Unproved oil and natural gas properties(1) .............................................................................................................
Total assets acquired ............................................................................................................................................
Liabilities assumed.................................................................................................................................................
Net assets acquired...............................................................................................................................................
Fair value of consideration paid for net assets:
Cash consideration .................................................................................................................................................
_____________________________________________________________________________
$
$
$
16,925
3,693
20,618
(122)
20,496
20,496
(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with
future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil
and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections
of future rates of production. The commodity prices utilized were based upon commodity strip prices as of July 12,
2012, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted
using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair
value hierarchy, as described in Note H.
D—Debt
1. Interest expense
The following amounts have been incurred and charged to interest expense for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Cash payments for interest ........................................................................................
Amortization of deferred loan costs and other adjustments ......................................
Accrued interest related to the October 2011 Notes(1)...............................................
Change in accrued interest.........................................................................................
Interest charges incurred .........................................................................................
Less capitalized interest.............................................................................................
Total interest expense ...........................................................................................
$
95,877
$
75,265
$
31,157
4,926
—
(221)
100,582
(255)
100,327
$
$
4,940
—
5,994
86,199
(627)
85,572
$
4,231
(3,378)
18,570
50,580
—
50,580
___________________________________________________________________
(1) As part of the October 19, 2011 offering of $200.0 million additional senior unsecured notes (further explained
below), the Company received $3.4 million in interest from the initial notes purchasers, which represents the interest
on such notes that accrued from August 15, 2011 to October 19, 2011, the date of the issuance of the notes. This
accrued interest was paid to the holders of such notes by Laredo on February 15, 2012.
2. 2022 Notes
On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8%
senior unsecured notes due 2022 (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7
3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year. The 2022 Notes are fully
and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Midstream (the “Guarantor”).
The 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27,
2012 (collectively, and as further supplemented, the “2012 Indenture”), among Laredo Inc, Wells Fargo Bank, National
Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and
covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments,
F-17
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
entering into transactions with affiliates and limitations on asset sales. Indebtedness under the 2022 Notes may be accelerated
in certain circumstances upon an event of default as set forth in the 2012 Indenture.
Laredo will have the option to redeem the 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the
redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1,
2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1,
2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any,
to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the 2022 Notes at a
redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus
accrued and unpaid interest, if any, to the redemption date. Furthermore, before May 1, 2015, Laredo may, at any time or from
time to time, redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of a public or private
equity offering at a redemption price of 107.375% of the principal amount of the 2022 Notes, plus any accrued and unpaid
interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2012
Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing
date of such equity offering. Laredo may also be required to make an offer to purchase the 2022 Notes upon a change of control
triggering event.
3. 2019 Notes
On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019
(the “January Notes”) and on October 19, 2011, Laredo completed an offering of an additional $200.0 million 9 1/2% senior
unsecured notes due 2019 (the “October 2011 Notes” and together with the January Notes, the “2019 Notes”). The 2019 Notes
will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on
February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed, jointly and severally on a
senior unsecured basis by the Guarantor.
The 2019 Notes were issued under and are governed by an indenture dated January 20, 2011 (as supplemented, the
“2011 Indenture”) among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The
Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the
payment of dividends or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and
limitations on asset sales. Indebtedness under the 2019 Notes may be accelerated in certain circumstances upon an event of
default as set forth in the Indenture.
Laredo will have the option to redeem the 2019 Notes, in whole or in part, at any time on or after February 15, 2015,
at the redemption prices (expressed as percentages of principal amount) of 104.750% for the 12-month period beginning on
February 15, 2015, 102.375% for the 12-month period beginning on February 15, 2016 and 100.000% for the 12-month period
beginning on February 15, 2017 and at any time thereafter, together with accrued and unpaid interest, if any, to the date of
redemption. In addition, before February 15, 2015, Laredo may redeem all or any part of the 2019 Notes at a redemption price
equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid
interest, if any, to the redemption date. Laredo may also be required to make an offer to purchase the 2019 Notes upon a change
of control triggering event.
4. Senior secured credit facility
As of December 31, 2013, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured
Credit Facility"), which matures November 4, 2018, had a capacity of $2.0 billion, with a borrowing base of $925.0 million
with an aggregate elected commitment of $825.0 million and no amounts outstanding. The borrowing base is subject to a semi-
annual redetermination based on the financial institutions' evaluation of the Company's oil and natural gas reserves. As defined
in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an
Adjusted Base Rate plus applicable margin and (ii) the Eurodollar advances under the facility bear interest, at the Company's
election, at the end of one-month, two-month, three-month, six-month or, to the extent available, 12-month interest periods (and
in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an
Adjusted London Interbank Offered Rate plus an applicable margin, based on the ratio of outstanding revolving credit to the
total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual commitment fee on the
unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit
to the total commitment under the Senior Secured Credit Facility. Subsequent to December 31, 2013, as a result of the issuance
by the Company of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022, the amount
available for borrowings and the aggregate elected commitment under the Senior Secured Credit Facility was decreased to
$812.5 million. See Note O.1 for additional information regarding this subsequent event.
F-18
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The Senior Secured Credit Facility is secured by a first priority lien on Laredo and the Guarantor's assets and stock,
including oil and natural gas properties, constituting at least 80% of the present value of the Company's proved reserves.
Further, the Company is subject to various financial and non-financial ratios on a consolidated basis, including a current ratio at
the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio
represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances
associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I)
its consolidated net income (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise
taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses;
and (v) other non-cash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit
Facility, to (II) the sum of net interest expense plus letter of credit fees of not less than 2.50 to 1.00, in each case for the four
quarters then ending. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company
was in compliance with these covenants as of December 31, 2013 and 2012.
Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of
total capacity or $20.0 million. No letters of credit were outstanding as of December 31, 2013.
5. Fair value of debt
The following table presents the carrying amount and fair value of the Company's debt instruments for the periods
presented:
(in thousands)
2019 Notes(1) ......................................................................................
2022 Notes .........................................................................................
Senior Secured Credit Facility ...........................................................
Total value of debt...........................................................................
December 31, 2013
December 31, 2012
Carrying
value
Fair
value
Carrying
value
Fair
value
$
$
551,538
500,000
615,313
549,375
$
551,760
500,000
$
616,000
541,250
—
$ 1,051,538
—
$ 1,164,688
165,000
$ 1,216,760
165,098
$ 1,322,348
________________________________________________________________________
(1) The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of $1.5 million and
$1.8 million as of December 31, 2013 and 2012, respectively.
As of December 31, 2013 and 2012, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was
determined using the December 31, 2013 and 2012 quoted market price (Level 1), respectively, and the fair value of the
outstanding debt as of December 31, 2012 on the Senior Secured Credit Facility was estimated utilizing pricing models for
similar instruments (Level 2). See Note H for information about fair value hierarchy levels.
E—Employee compensation
In November 2011, Laredo's Board of Directors approved a Long-Term Incentive Plan (the "LTIP"), which provides for
the granting of incentive awards in the form of restricted stock awards, restricted stock option awards and other awards. The
LTIP provides for the issuance of 10.0 million shares.
The Company recognizes the fair value of stock-based payments to employees and directors as a charge against
earnings. The Company recognizes stock-based payment expense over the requisite service period. Laredo's stock-based
compensation awards are accounted for as equity instruments. Stock-based compensation is included in "General and
administrative" in the consolidated statements of operations.
1. Restricted stock awards
All restricted stock awards are non-participating securities and are treated as issued and outstanding in the
accompanying consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the
awarded shares are forfeited, canceled and are no longer considered issued and outstanding. Restricted stock awards converted in
the Corporate Reorganization vested 20% at the grant date and then vest 20% annually thereafter. The restricted stock awards
granted under the LTIP to employees generally vest 33%, 33% and 34% per year beginning on the first anniversary date of the
grant. Restricted stock awards granted to non-employee directors vest fully on the anniversary date of the grant.
F-19
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following table reflects the outstanding restricted stock awards for the years ended December 31, 2013 and 2012
and from the Corporate Reorganization until December 31, 2011:
(in thousands, except for grant date fair values)
Outstanding as of December 19, 2011................................................................................
Exchanged ........................................................................................................................
Vested...............................................................................................................................
Outstanding as of December 31, 2011................................................................................
Granted .............................................................................................................................
Forfeited............................................................................................................................
Vested(1).............................................................................................................................
Outstanding as of December 31, 2012................................................................................
Granted .............................................................................................................................
Forfeited............................................................................................................................
Vested(2).............................................................................................................................
Outstanding as of December 31, 2013................................................................................
______________________________________________________________________________
Restricted
stock awards
Weighted average
grant date
fair value
— $
912
$
(1) $
$
911
932
$
(251) $
(397) $
$
1,195
1,469
$
(229) $
(636) $
$
1,799
—
1.14
1.11
1.14
22.90
15.61
1.03
15.06
18.17
18.47
18.69
19.17
(1) Vestings in the year ended December 31, 2012 related to restricted stock awards converted in the Corporate
Reorganization. Such shares have a tax basis of zero to the grantee and therefore result in no tax benefit to the
Company.
(2) The vesting of certain restricted stock grants could result in federal and state income tax expense or benefits related to
the difference between the market price of the common stock at the date of vesting and the date of grant. The total fair
value of restricted stock vested during the year ended December 31, 2013 was $8.9 million. The Company recognized
excess income tax expense of $0.4 million during the year ended December 31, 2013 related to restricted stock, which
was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in the years
ended December 31, 2012 or 2011.
The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting
restricted stock awards. As of December 31, 2013, unrecognized stock-based compensation expense related to restricted stock
awards was $23.3 million. Such cost is expected to be recognized over a weighted average period of 1.83 years.
F-20
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
2. Restricted stock option awards
Restricted stock options awards granted under the LTIP vest and are exercisable in four equal installments on each of
the first four anniversaries of the date of the grant. The following table reflects the stock option award activity for the years
ended December 31, 2013 and 2012:
(in thousands, except for weighted average exercise price and contractual term)
Restricted
stock option
awards
Weighted average
exercise price
(per option)
Weighted average
contractual term
(years)
Outstanding as of December 31, 2011.................................................
Granted ..............................................................................................
Forfeited ............................................................................................
Outstanding as of December 31, 2012.................................................
Granted ..............................................................................................
Exercised(1) ........................................................................................
Expired or canceled ...........................................................................
Forfeited ............................................................................................
Outstanding as of December 31, 2013.................................................
Vested and exercisable at end of period(2)............................................
Vested, exercisable, and expected to vest at end of period(3) ...............
_____________________________________________________________________________
— $
603
$
(144) $
$
459
1,019
$
(104) $
(12) $
(133) $
$
1,229
$
158
$
1,197
—
24.11
24.11
24.11
17.34
20.79
24.11
19.88
19.32
22.12
19.33
—
10
10
10
9.13
8.75
—
—
8.82
8.40
8.82
(1) The exercise of stock options could result in federal and state income tax expense or benefits related to the difference
between the fair value of the stock option at the date of grant and the intrinsic value of the stock option when exercised.
The intrinsic value of a stock option is the amount by which the market value upon exercise of the underlying stock
exceeds the exercise price of the option. The total intrinsic value of options exercised during the year ended December
31, 2013 was $0.9 million. The Company recognized excess income tax expense of $0.1 million during the year ended
December 31, 2013, related to stock options, which was recorded as an adjustment to deferred income taxes. There
were no comparative amounts recorded in years ended December 31, 2012 or 2011.
(2) The aggregate intrinsic value of vested and exercisable options at December 31, 2013 was $0.9 million.
(3) The aggregate intrinsic value of vested, exercisable and expected to vest options at December 31, 2013 was $10.0
million.
The Company used the Black-Scholes option pricing model to determine the fair value of restricted stock options and is
recognizing the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining
the fair value of stock-based awards requires judgment, including estimating the expected term that stock options will be
outstanding prior to exercise, and the associated volatility. As of December 31, 2013 unrecognized stock-based compensation
expense related to restricted option awards was $8.3 million. Such cost is expected to be recognized over a weighted average
period of 2.89 years.
F-21
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The assumptions used to estimate the fair value of restricted stock options granted are as follows:
Risk-free interest rate(1) .......................................................................................................
Expected option life(2) .........................................................................................................
Expected volatility(3) ...........................................................................................................
Fair value per option ...........................................................................................................
$
1.19%
1.14%
6.25 years
6.25 years
58.89%
9.67
$
59.98%
13.52
_______________________________________________________________________________
February 15, 2013
February 3, 2012
(1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury
yield terms to the expected life of the option.
(2) As the Company had no historical exercise history at the time of the grant, expected option life assumptions were
developed using the simplified method in accordance with GAAP.
(3) The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to
develop the expected volatility.
In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance
with the following schedule based upon the number of full years of the optionee's continuous employment or service with the
Company, following the date of grant:
Full years of continuous employment
Incremental percentage of
option exercisable
Cumulative percentage of
option exercisable
Less than one ................................................................................................
One ...............................................................................................................
Two...............................................................................................................
Three.............................................................................................................
Four ..............................................................................................................
—%
25%
25%
25%
25%
—%
25%
50%
75%
100%
No shares of common stock may be purchased unless the optionee has remained in the continuous employment of the
Company through a year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not
exercised within 10 years from the grant date. The unvested portion of an option will expire upon termination of employment of
the optionee, and the vested portion of such option will remain exercisable for (A) one year following termination of
employment by death, but not later than the expiration of the option period or (B) 90 days following termination of employment
or service without cause, but not later than the expiration of the option period. The unvested and the unexercised vested portion
of the option will expire upon termination of employment for cause.
3. Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Restricted stock award compensation expense..........................................................
Restricted stock option award compensation expense ..............................................
Total stock-based compensation expense................................................................
$
$
17,084
4,349
21,433
$
$
8,496
1,560
10,056
$
$
6,111
—
6,111
During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option
awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of
employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications
recognized during the year ended December 31, 2013 was $4.7 million.
4. Performance unit awards
The performance unit awards issued to management are subject to a combination of market and service vesting criteria.
A Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of the awards at
the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP.
The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the Company and the volatilities of a
F-22
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
group of peer companies that have been determined to be most representative of the Company. These awards are accounted for
as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain
performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing
the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service
has already been provided. The Company issued performance unit awards on February 15, 2013 ("2013 performance unit
awards") and on February 3, 2012 ("2012 performance unit awards").
The 2013 performance unit awards have a performance period of January 1, 2013 to December 31, 2015 and are
expected to be paid in 2016 if the performance criteria is met. The 2012 performance unit awards have a performance period of
January 1, 2012 to December 31, 2014 and are expected to be paid in 2015 if the performance criteria is met. There were no
performance unit awards issued or outstanding during the year ended December 31, 2011.
The following table reflects the outstanding performance unit awards for the periods presented:
(in thousands)
Outstanding at December 31, 2011 ........................................................................................
Granted.................................................................................................................................
Forfeited...............................................................................................................................
Outstanding at December 31, 2012 ........................................................................................
Granted.................................................................................................................................
Forfeited...............................................................................................................................
Vested (1)...............................................................................................................................
Outstanding at December 31, 2013 ........................................................................................
_______________________________________________________________________________
2013 performance
unit awards
2012 performance
unit awards
—
—
—
—
58
(4)
(10)
44
—
49
(2)
47
—
(9)
(11)
27
(1) During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the
officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
The assumptions used to estimate the fair value of the respective performance unit awards as of December 31, 2013 are
as follows:
2013 performance
unit awards
2012 performance
unit awards
Risk-free rate(1) .......................................................................................................................
Dividend yield ........................................................................................................................
Expected volatility(2)...............................................................................................................
Laredo closing price as of December 31, 2013 ......................................................................
$
0.38%
—%
37.34%
27.69
$
0.13%
—%
37.42%
27.69
_______________________________________________________________________________
(1) The risk-free rate was derived using a zero-coupon yield calculated from the Treasury Constant Maturities yield curve.
(2) The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to
develop the expected volatility.
The fair value of the 2013 performance unit awards and 2012 performance unit awards as of December 31, 2013 were
$5.7 million and $3.8 million, respectively. The fair value of the 2012 performance unit awards as of December 31, 2012 was
$5.4 million.
F-23
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following has been recorded to performance unit award compensation expense for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2013 Performance unit award compensation expense ....................................................................
2012 Performance unit award compensation expense ....................................................................
Total performance unit award compensation expense .................................................................
$
$
2,863
1,870
4,733
$
$
—
1,797
1,797
Compensation expense for these awards is recognized in "General and administrative" in the Company's consolidated
statements of operations and the corresponding liability is included in "Other noncurrent liabilities" in the consolidated balance
sheets. As there are inherent uncertainties related to the factors and the Company's judgment in applying them to the fair value
determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately
earned by the members of management.
5. Defined contribution plan
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of
hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation,
not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of
an employee’s compensation and may make additional discretionary contributions for eligible employees. Employees are 100%
vested in the employer contributions upon receipt.
The following table presents total employer contributions to the plans for the periods presented:
(in thousands)
Contributions ...............................................................................................................
For the years ended December 31,
2013
2012
2011
$
1,886
$
1,293
$
1,651
F-24
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
F—Income taxes
The Company uses an asset and liability approach for financial accounting and for reporting income tax. Deferred
income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes.
The Company is subject to corporate income taxes and the Texas franchise tax. Income tax expense attributable to
income from continuing operations for the periods presented consisted of the following:
(in thousands)
Current taxes:
Federal.....................................................................................................................
State.........................................................................................................................
Deferred taxes:
Federal.....................................................................................................................
State.........................................................................................................................
Income tax expense...............................................................................................
For the years ended December 31,
2013
2012
2011
$
$
— $
—
— $
—
—
—
(64,034)
(10,473)
(74,507) $
(31,390)
(1,613)
(33,003) $
(58,965)
(647)
(59,612)
The following presents the comprehensive provision for income taxes for the periods presented:
(in thousands)
Comprehensive provision for income taxes allocable to:
For the years ended December 31,
2013
2012
2011
Continuing operations .............................................................................................
Discontinued operations..........................................................................................
Comprehensive provision for income taxes .........................................................
$
$
(74,507) $
(781)
(75,288) $
(33,003) $
54
(32,949) $
(59,612)
238
(59,374)
Income tax expense attributable to income from continuing operations before income taxes differed from amounts
computed by applying the applicable federal income tax rate of 34% to pre-tax earnings as a result of the following:
(in thousands)
Income tax expense computed by applying the statutory rate...................................
State income tax, net of federal tax benefit and increase in valuation allowance .....
Non-deductible stock-based compensation ...............................................................
Stock-based compensation tax deficiency.................................................................
Change in deferred tax valuation allowance .............................................................
Income from nontaxable entity..................................................................................
Other items ................................................................................................................
Income tax expense .................................................................................................
$
$
For the years ended December 31,
2013
2012
2011
(64,969) $
(7,532)
(1,070)
(559)
(63)
—
(314)
(74,507) $
(32,219) $
(102)
(1,177)
—
583
—
(88)
(33,003) $
(56,300)
(2,530)
(2,078)
—
660
30
606
(59,612)
The effective tax rate for the Company's continuing operations was 39%, 35% and 36% for the years ended December
31, 2013, 2012 and 2011, respectively. The Company's effective tax rate is affected by recurring permanent differences and by
discrete items that may occur in any given year, but are not consistent from year to year.
During the year ended December 31, 2013, certain shares related to restricted stock awards vested at times when the
Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction
related to such shares is less than the expense previously recognized for book purposes. During the year ended December 31,
2013, certain restricted stock options were exercised. The income tax deduction related to the options intrinsic value was less
than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in
capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously
recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.6 million for the year ended
F-25
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no
comparative amounts for the years ended December 31, 2012 or 2011.
The Company filed its 2012 federal and Oklahoma income tax returns during the year ended December 31, 2013. As a
result, the Company recognized an aggregate expense from tax related items, primarily the result of Oklahoma income
allocation updates. The Oklahoma income allocation expense reflects a change to the applicable methodology for allocating
income between certain states in the fiscal 2012 and prior-year returns. The tax impact of these items of $2.4 million for the
year ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There
were no comparative amounts for the years ended December 31, 2012 or 2011.
Significant components of the Company's deferred tax (liabilities) assets as of December 31 are as follows:
(in thousands)
2013
2012
Net operating loss carry-forward ......................................................................................................
Oil and natural gas properties and equipment...................................................................................
Derivatives ........................................................................................................................................
Stock-based compensation ................................................................................................................
Accrued bonus...................................................................................................................................
Capitalized interest............................................................................................................................
Other..................................................................................................................................................
Gross deferred tax (liability) asset..................................................................................................
Valuation allowance..........................................................................................................................
Net deferred tax (liability) asset .....................................................................................................
$
$
284,890
(278,735)
(30,859)
6,578
$
222,017
(175,823)
7,108
3,740
2,099
(240)
(12,527)
(132)
(12,659) $
2,928
3,502
1,850
1,113
62,695
(66)
62,629
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:
(in thousands)
2013
2012
Deferred tax asset..............................................................................................................................
Deferred tax liability .........................................................................................................................
Net deferred tax (liability) assets....................................................................................................
$
$
$
3,634
(16,293)
(12,659) $
62,629
—
62,629
The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates
as of December 31, 2013:
(in thousands)
2026..........................................................................................................................................................................
2027..........................................................................................................................................................................
2028..........................................................................................................................................................................
2029..........................................................................................................................................................................
2030..........................................................................................................................................................................
2031..........................................................................................................................................................................
2032..........................................................................................................................................................................
2033..........................................................................................................................................................................
Total.......................................................................................................................................................................
$
2,741
38,651
228,661
101,932
82,948
74,151
135,390
154,538
819,012
$
The Company had federal net operating loss carry-forwards totaling $819.0 million and state of Oklahoma net
operating loss carry-forwards totaling $180.1 million as of December 31, 2013. These carry-forwards begin expiring in 2026.
As of December 31, 2013, the Company believes the federal and state of Oklahoma net operating loss carry-forwards are fully
realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the
weight of that evidence, a valuation allowance was needed on either the federal or Oklahoma net operating loss carry-forwards.
Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows
from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded
as of December 31, 2013, the Company’s ability to capitalize intangible drilling costs, rather than expensing these costs in
order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.
F-26
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The Company's federal and state operating loss carry-forwards include windfall tax deductions from vestings of
certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The
amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in
income taxes payable. As of December 31, 2013, the Company had suspended additional paid-in capital credits of $0.9 million
related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions,
the Company would record a benefit of up to $0.9 million in additional paid-in capital.
The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely
than not to be realized. As of December 31, 2013, a full valuation allowance of $0.1 million was recorded against the deferred
tax asset related to the Company’s charitable contribution carry-forward of $0.4 million.
In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed
a policy for identifying uncertain tax positions that considers support for each position, industry standard, tax return disclosure
and schedule, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits
during the year ended December 31, 2013.
Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a
consolidated basis. Following the Internal Consolidation, the surviving entities will file a single return. The Company's income
tax returns for the years 2010 through 2013 remain open and subject to examination by federal tax authorities and/or the tax
authorities in Oklahoma, Texas and Louisiana which are the jurisdictions where the Company has or had operations. The
Company's 2011 federal income tax return is currently under examination. Additionally, the statute of limitations for
examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in
a tax return.
G—Derivatives
1. Commodity derivatives
The Company engages in derivative transactions such as collars, swaps, puts and basis swaps to hedge price risks due
to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of December 31, 2013, the
Company had 37 open derivative contracts with financial institutions which extend from January 2014 to June 2018, none of
which were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance
sheets and gains and losses are recognized in current period earnings.
Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor
established by these collars, the Company receives an amount from its counterparty equal to the difference between the
settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price
ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the
settlement price and the price ceiling multiplied by the hedged contract volume.
Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company
pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the
hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount
equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
Each put transaction has an established floor price. The Company pays the counterparty a premium in order to enter
into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount
equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the
settlement price is above the floor price, the put option expires.
Each oil basis swap transaction has an established fixed basis differential. The Company's oil basis swap differentials
are between the West Texas Intermediate Midland Argus ("Midland") index crude oil price and the West Texas Intermediate
Argus Cushing ("WTI Argus") index crude oil price or the Light Louisiana Sweet Argus ("LLS Argus") index crude oil price
and the Brent International Petroleum Exchange ("Brent") index crude oil price. When the WTI Argus price less the fixed basis
differential is greater than the actual Midland price, the difference multiplied by the hedged contract volume is paid to the
Company by the counterparty. When the WTI Argus price less the fixed basis differential is less than the actual Midland price,
the difference multiplied by the hedged contract volume is paid by the Company to the counterparty. When the Brent price less
the fixed basis differential is greater than the actual LLS Argus price, the difference multiplied by the hedged contract volume
is paid to the Company by the counterparty. When the LLS Argus price less the fixed basis differential is less than the actual
Brent price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.
F-27
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Gains and losses on derivatives are reported on the consolidated statements of operations in the respective “Gain (loss)
on derivatives” amounts.
During the year ended December 31, 2013, the Company entered into additional commodity contracts to hedge a
portion of its estimated future production. The following table summarizes information about these additional commodity
derivative contracts:
Oil (volumes in Bbl):
Swap
Basis swap(1)
Swap
Swap
Swap
Swap
Swap
Swap
Price collar
Price collar
Price collar
Price collar
Basis swap(2)
Price collar
Price collar
Price collar
Price collar
Price collar
Price collar
Price collar
Price collar
Price collar
Aggregate
volumes
Swap
price
Floor
price
Ceiling
price
Contract period
1,377,000
4,026,000
80,000
$ 98.10
$ — $ —
$ (1.00) $ — $ —
$ — $ —
$101.20
March 2013 - December 2013
March 2013 - December 2014
August 2013 - December 2013
204,000
$106.60
$ — $ —
October 2013 - December 2013
912,500
$ 93.65
$ — $ —
January 2014 - December 2014
365,000
$ 93.68
$ — $ —
January 2014 - December 2014
399,996
480,000
555,000
555,000
555,000
555,000
14,610,000
1,277,500
690,000
1,928,760
364,380
1,084,380
600,000
360,000
1,281,000
$ 93.30
$ 97.47
$ — $ —
$ — $ —
January 2014 - December 2014
January 2014 - December 2014
$ — $ 90.00
$ — $ 90.00
$ 97.00
$ 97.05
January 2014 - December 2014
January 2014 - December 2014
$ 96.93
$ — $ 90.00
$ — $ 90.00
$ 96.90
$ (2.85) $ — $ —
$ 98.50
$ — $ 80.00
$ 95.87
$ — $ 80.00
$ — $ 80.00
$ — $ 80.00
$ — $ 80.00
$ — $ 80.00
$ — $ 80.00
$ — $ 80.00
$ 92.00
$ 92.05
$ 92.16
$ 92.30
$ 92.35
$ 93.00
January 2014 - December 2014
January 2014 - December 2014
July 2014 - June 2018
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
January 2016 - December 2016
579,000
$ — $ 80.00
$ 87.75
January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar
Swap
Swap
2,900,000
3,338,400
3,978,500
$
$ — $ 3.00
$
$
4.00
$ — $ —
$ — $ —
4.31
4.36
March 2013 - December 2013
June 2013 - December 2013
January 2014 - December 2014
______________________________________________________________________________
(1) The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price
and the Midland oil futures.
(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil
price and the Brent index crude oil price.
F-28
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer
in connection with the Anadarko Basin Sale:
Natural gas (volumes in MMBtu):
Swap.....................................................................................
Swap.....................................................................................
2,386,800
3,978,500
$
$
4.31
4.36
August 2013 - December 2013
January 2014 - December 2014
Aggregate
volumes
Swap
price
Contract period
During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred
premiums, in settlements from early terminations and modifications of commodity derivative contracts. There were no
comparable amounts recorded in the years ended December 31, 2012 or 2011. Gains and losses on early terminated derivatives
are reported on the consolidated statements of operations in the respective “Gain (loss) on derivatives” amounts.
The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the
year ended December 31, 2013:
Natural gas (volumes in MMBtu):
Price collar............................................................
Put.........................................................................
Price collar............................................................
Price collar............................................................
Price collar............................................................
Price collar............................................................
Price collar............................................................
Price collar............................................................
Price collar............................................................
Aggregate
volumes
Floor
price
Ceiling
price
Contract period
2,200,000
2,200,000
3,480,000
1,800,000
1,680,000
1,560,000
2,520,000
2,400,000
2,400,000
$
$
$
$
$
$
$
$
$
4.00
4.00
4.00
4.00
4.00
3.00
3.00
3.00
3.00
September 2013 - December 2013
$ 7.05
$ — September 2013 - December 2013
$ 7.00
$ 7.05
$ 7.05
$ 5.50
$ 6.00
$ 6.00
$ 6.00
January 2014 - December 2014
January 2014 - December 2014
January 2014 - December 2014
January 2014 - December 2014
January 2015 - December 2015
January 2015 - December 2015
January 2015 - December 2015
F-29
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following table summarizes open positions as of December 31, 2013, and represents, as of such date, derivatives
in place through June 2018, on annual production volumes:
Year
2014
Year
2015
Year
2016
Year
2017
Year
2018
Oil positions:
Puts:
Hedged volume (Bbl)................................................................
Weighted average price ($/Bbl) ................................................
540,000
75.00
$
Swaps:
Hedged volume (Bbl)................................................................
Weighted average price ($/Bbl) ................................................
2,157,496
94.44
$
456,000
75.00
$
—
— $
$
$
—
— $
—
— $
Collars:
Hedged volume (Bbl)................................................................
Weighted average floor price ($/Bbl)........................................
Weighted average ceiling price ($/Bbl).....................................
Basis swaps:
Hedged volume(1) (Bbl).............................................................
Weighted average price(1) ($/Bbl) .............................................
Hedged volume(2) (Bbl).............................................................
Weighted average price(2) ($/Bbl) .............................................
$
$
$
$
Natural gas positions:
Collars:
2,946,000
86.42
104.89
6,557,020
79.81
95.40
$
$
1,860,000
80.00
91.37
$
$
$
$
2,252,000
(1.04) $
—
— $
—
— $
1,840,000
3,650,000
3,660,000
3,650,000
(2.85) $
(2.85) $
(2.85) $
(2.85) $
—
— $
—
— $
—
— $
— $
—
— $
—
—
—
—
—
—
—
—
—
1,810,000
(2.85)
Hedged volume (MMBtu).........................................................
Weighted average floor price ($/MMBtu).................................
Weighted average ceiling price ($/MMBtu) .............................
9,600,000
3.00
5.50
$
$
8,160,000
3.00
6.00
$
$
$
$
—
— $
— $
—
— $
— $
—
—
—
_______________________________________________________________________________
(1) The associated oil basis swap derivatives are settled based on the differential between the WTI Argus index oil price
and the Midland oil futures.
(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index oil price and
the Brent oil price.
The following represents cash settlements received (paid) for matured derivatives for the periods presented:
(in thousands)
Commodity derivatives received ......................................................................
Interest rate derivatives paid .............................................................................
Cash settlements received (paid) for matured derivatives, net .......................
$
$
For the years ended December 31,
2013
2012
2011
4,046
(301)
3,745
$
$
27,025
(2,115)
24,910
$
$
3,719
(4,873)
(1,154)
2. Interest rate derivatives
The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior
Secured Credit Facility. Interest rate derivative agreements are used to manage a portion of the exposure related to changing
interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") is lower than
the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the
counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not
designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments are recorded
in current earnings. The Company had one interest rate swap and one interest rate cap outstanding for a notional amount of
$100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate
derivatives were in place as of December 31, 2013.
F-30
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
3. Balance sheet presentation
The Company’s oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis as
“Derivatives” in the consolidated balance sheets.
The following summarizes the fair value of derivatives outstanding on a gross basis as of:
(in thousands)
Assets:
Commodity derivatives:
Oil derivatives .....................................................................................................
Natural gas derivatives........................................................................................
Total assets........................................................................................................
Liabilities:
Commodity derivatives:
Oil derivatives(1) ..................................................................................................
Natural gas derivatives(2).....................................................................................
Interest rate derivatives ............................................................................................
Total liabilities .................................................................................................
Net derivative position ...............................................................................................
______________________________________________________________________________
December 31, 2013
December 31, 2012
$
$
$
$
$
140,496
657
141,153
56,818
2,278
—
59,096
82,057
$
$
$
$
$
16,219
17,896
34,115
21,308
10,413
277
31,998
2,117
(1) The oil derivatives fair value includes a deferred premium liability of $11.1 million and $18.3 million as of
December 31, 2013 and 2012, respectively.
(2) The natural gas derivatives fair value includes a deferred premium liability of $1.6 million and $6.4 million as of
December 31, 2013 and 2012, respectively.
By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, the Company
exposes itself to credit risk and market risk. Market risk is the exposure to changes in the market price of oil and natural gas,
which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of
the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive,
the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Senior
Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required
to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk
in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only
with counterparties that are also lenders in the Senior Secured Credit Facility and meet the Company’s minimum credit quality
standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring
the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard
practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such
derivatives and, therefore, the risk of such loss is somewhat mitigated as of December 31, 2013.
H—Fair value measurements
The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value. The fair value
of the derivatives are determined utilizing pricing models for similar instruments. The models use a variety of techniques to
arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and
forward curves generated from a compilation of data gathered from third parties.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the
valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in
active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the
valuation techniques as follows:
F-31
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical
assets or liabilities in an active market that management has the ability to access. Active markets are considered
to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not
active or model inputs that are observable either directly or indirectly for substantially the full term of the assets
or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the
price risk management instrument and can be derived from observable data or supported by observable levels at
which transactions are executed in the marketplace.
Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that
require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable
inputs are not corroborated by market data. These inputs reflect management’s own assumptions about the
assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the
level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair
value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis.
Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.
Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No
transfers between fair value hierarchy levels occurred during the years ended December 31, 2013 or 2012.
1. Fair value measurement on a recurring basis
The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a
recurring basis as of December 31, 2013 and 2012.
(in thousands)
As of December 31, 2013:
Commodity derivatives ...................................................................
Deferred premiums..........................................................................
Total...............................................................................................
(in thousands)
As of December 31, 2012:
Commodity derivatives ...................................................................
Deferred premiums..........................................................................
Interest rate derivatives....................................................................
Total...............................................................................................
Level 1
Level 2
Level 3
Total fair
value
— $
—
— $
94,741
—
94,741
$
$
— $
(12,684)
(12,684) $
94,741
(12,684)
82,057
Level 1
Level 2
Level 3
Total fair
value
— $
—
—
— $
27,103
$
— $
—
(277)
26,826
$
(24,709)
—
(24,709) $
27,103
(24,709)
(277)
2,117
$
$
$
$
These items are included in "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions
associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of commodity derivatives
include the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data.
Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis
of interest rate swaps include the interest rate curves, appropriate risk adjusted discount rates and other relevant data.
The Company’s deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as
the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a
recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative
contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net
present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates
range from 2.00% to 3.56%) and then records the change in net present value to interest expense over the period from trade
until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred
premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a
significantly lower (higher) fair value measurement for each new deal containing a deferred premium entered into; however,
F-32
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
the valuation for the deals already recorded would remain unaffected. While the Company believes the sources utilized to arrive
at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore,
on a quarterly basis, the valuation is compared to counterparty valuations and third-party valuation of the deferred premiums
for reasonableness.
The following table presents actual cash payments required for deferred premium contracts in place as of December
31, 2013, and for the calendar years following:
(in thousands)
2014..................................................................................................................................................................
2015..................................................................................................................................................................
2016..................................................................................................................................................................
Total................................................................................................................................................................
$
$
7,419
5,166
358
12,943
A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:
(in thousands)
For the year ended
December 31, 2013
Balance of Level 3 at beginning of period .......................................................................................................
Change in net present value of deferred premiums for derivatives..................................................................
Settlements(1) ....................................................................................................................................................
Balance of Level 3 at end of period .................................................................................................................
$
$
(24,709)
(462)
12,487
(12,684)
(in thousands)
For the year ended
December 31, 2012
Balance of Level 3 at beginning of period .......................................................................................................
Change in net present value of deferred premiums for derivatives..................................................................
Total purchases and settlements:
Purchases........................................................................................................................................................
Settlements.....................................................................................................................................................
Balance of Level 3 at end of period .................................................................................................................
$
$
(18,868)
(668)
(11,291)
6,118
(24,709)
(in thousands)
For the year ended December 31, 2011
Derivative
option
contracts
Deferred
premiums
Balance of Level 3 at beginning of period.............................................................................
Gains (losses) included in earnings........................................................................................
Change in net present value of deferred premiums for derivatives .......................................
Total purchases and settlements:
Purchases .............................................................................................................................
Settlements ..........................................................................................................................
Transfers out of Level 3(2)(3) ...................................................................................................
Balance of Level 3 at end of period .......................................................................................
$
$
$
20,026
5,323
—
—
—
(25,349)
— $
(12,495)
—
(471)
(5,988)
86
—
(18,868)
___________________________________________________________________
(1) The settlement amounts for the year ended December 31, 2013 include $2.2 million in deferred premiums which were
settled net with the early terminated contracts from which they derive.
(2) The Company transferred the commodity derivative option contracts out of Level 3 during the year ended
December 31, 2011 due to the Company's ability to utilize transparent forward price curves and volatilities published
and available through independent third party vendors. As a result, the Company transferred positions from Level 3 to
Level 2 as the significant inputs used to calculate the fair value are all observable.
F-33
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
(3) The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or change in
circumstances that caused the transfer.
2. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets (see Note B.20), if any, at fair value on a nonrecurring
basis in accordance with GAAP. For purposes of fair value measurement, it was determined that the impairment of long-lived
assets are classified as Level 3 based on the use of internally developed cash flow models. No impairments of long-lived assets
were recorded in the years ended December 31, 2013, 2012 or 2011. See Note B.20 for discussion of the Company's
impairment of materials and supplies in the year ended December 31, 2011.
The accounting policies for impairment of oil and natural gas properties are discussed in Note B.20. Significant inputs
included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of
operating and development costs, anticipated production of proved reserves and other relevant data.
I—Credit risk
The Company's oil and natural gas sales are to a variety of purchasers, including intrastate and interstate pipelines or
their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from
a number of oil and natural gas companies, partnerships, individuals and others who own interests in the properties operated by
the Company. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset
by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the
recoverability of all material trade and other receivables to determine collectability.
The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and its exposure to interest
rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk
from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting
under agreements governing such derivatives and therefore, the credit risk associated with its derivative counterparties is
somewhat mitigated. See Note G for additional information regarding the Company's derivatives.
For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7%
of total revenues, with two of the three customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts
receivable as of December 31, 2013. For the year ended December 31, 2012, the Company had three customers that accounted
for 34.0%, 12.3% and 10.0% of total revenues, with the same three customers accounting for 25.7%, 13.0% and 10.7% and
another customer accounting for 13.7% of oil and natural gas sales accounts receivable as of December 31, 2012. For the year
ended December 31, 2011, the Company had three customers that accounted for 36.1%, 16.2% and 12.9% of total revenues,
with the same three customers accounting for 31.6%, 13.9% and 15.9% and another customer accounting for 11.0% of oil and
natural gas sales accounts receivable as of December 31, 2011.
As of December 31, 2013, the Company had four partners whose joint operations accounts receivable accounted for
16.0%, 14.1%, 13.1% and 10.9% of the Company's total joint operations accounts receivable. As of December 31, 2012, the
Company had two partners whose joint operations accounts receivable accounted for 66.2% and 17.0% of the Company's total
joint operations accounts receivable.
The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had a cash balance on
deposit with certain banks in the Senior Secured Credit Facility bank group as of December 31, 2013, which exceeded the
balance insured by the FDIC in the amount of $240.5 million. Management believes that the risk of loss is mitigated by the
bank's reputation and financial position.
F-34
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Related-party transactions
The Company has a gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg
Pincus IX, a major stockholder of Laredo, and other affiliates of Warburg Pincus LLC, held material investment interests in
Targa until May 2013. One of Laredo's directors is on the board of directors of affiliates of Targa. The following table
summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from the Company's
related party and included in the consolidated statements of operation for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Net oil and natural gas sales .................................................................................................
$ 74,245
$ 71,916
$ 79,300
The following table summarizes the amounts included in oil and natural gas sales receivable from the Company's
related party in the consolidated balance sheets for the periods presented:
(in thousands)
December 31,
December 31,
2013
2012
Oil and natural gas sales receivable ..................................................................................................
$
9,064
$
6,244
J—Commitments and contingencies
1. Lease commitments
The Company leases equipment and office space under operating leases expiring on various dates through 2022.
Minimum annual lease commitments as of December 31, 2013, and for the calendar years following are:
(in thousands)
2014 ............................................................................................................................................................................
2015 ............................................................................................................................................................................
2016 ............................................................................................................................................................................
2017 ............................................................................................................................................................................
2018 ............................................................................................................................................................................
Thereafter....................................................................................................................................................................
Total..........................................................................................................................................................................
1,994
2,088
1,923
1,823
1,738
1,367
10,933
$
The following has been recorded to rent expense for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Rent expense..............................................................................................................
$
1,923
$
1,339
$
1,175
The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the
lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the
difference between the straight-line amount and the actual amounts of the lease payments.
2. Litigation
The Company may be involved in legal proceedings or is subject to industry rulings that could bring rise to claims in
the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any
pending litigation or pending claims will be material or have a material adverse effect on the Company’s business, financial
position, results of operations or liquidity.
F-35
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
3. Drilling contracts
The Company has committed to several short-term drilling contracts with various third parties in order to complete its
various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant
penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company’s
financial statements upon contract termination. These commitments are not recorded in the accompanying consolidated balance
sheets. Future commitments are $40.8 million as of December 31, 2013. Management does not anticipate canceling any drilling
contracts or discontinuing drilling efforts in 2014.
4. Federal and state regulations
Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws,
rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory
burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes
that it is in compliance with currently applicable state and federal regulations related to oil and natural gas exploration and
production, and that compliance with the current regulations will not have a material adverse impact on the financial position or
results of operations of the Company. Because these rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with these regulations.
K—Net income per share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of shares
outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock
awards. The effect of the Company's outstanding options that were granted in February 2012 to purchase 359,002 shares of
common stock at $24.11 per share were excluded from the calculation of diluted net income (loss) per share for each of the
years ended December 31, 2013 and 2012, because the exercise price of those options was greater than the average market price
during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the
Company's outstanding options that were granted in February 2013 to purchase 869,938 shares of common stock at $17.34 per
share were excluded from the calculation of diluted net income (loss) per share for the year ended December 31, 2013, because,
utilizing the treasury method, the sum of the assumed proceeds exceeds the average stock price during the period and, therefore,
the inclusion of these outstanding options would have been anti-dilutive.
F-36
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
The following is the calculation of basic and diluted weighted average shares outstanding and net income per share for
the periods presented:
(in thousands, except for per share data)
Net income (loss) (numerator):
For the years ended December 31,
2013
2012
2011
Income from continuing operations—basic and diluted.................................
Income (loss) from discontinued operations, net of tax—basic and diluted ..
Net income—basic and diluted ....................................................................
$
$
116,577
1,423
118,000
$
$
61,761
(107)
61,654
$
$
105,976
(422)
105,554
Weighted average shares (denominator):
Weighted average shares—basic(1) .................................................................
Non-vested restricted stock(2)..........................................................................
Weighted average shares—diluted...............................................................
Net income (loss) per share:
Basic:
Income from continuing operations...............................................................
Income (loss) from discontinued operations, net of tax ................................
Net income per share ....................................................................................
Diluted:
Income from continuing operations...............................................................
Income (loss) from discontinued operations, net of tax ................................
Net income per share ....................................................................................
_______________________________________________________
132,490
1,888
134,378
126,957
1,214
128,171
107,187
912
108,099
$
$
$
$
0.88
0.01
0.89
0.87
0.01
0.88
$
$
$
$
0.49
—
0.49
0.48
—
0.48
$
$
$
$
0.99
(0.01)
0.98
0.98
—
0.98
(1) For the year ended December 31, 2013, weighted average shares outstanding used in the computation of basic and
diluted net income per share attributable to stockholders has been computed taking into account the Follow-on
Offering.
(2) For the year ended December 31, 2011, weighted average shares outstanding used in the computation of basic and
diluted net income per share attributable to stockholders has been computed taking into account (i) restricted stock
awards converted in the Corporate Reorganization as if the conversion occurred as of the beginning of the year and
(ii) the 20,125,000 shares of common stock issued by the Company in the IPO.
L—Recently issued accounting standards
In July 2013, the Financial Accounting Standards Board ("FASB") issued guidance on the presentation of
unrecognized tax benefits when a net operating loss carry-forward, a similar tax loss, or a tax credit carry-forward exists at the
reporting date. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15,
2013. The Company does not expect the adoption to have an impact on the consolidated financial statements.
M—Variable interest entity
An entity is referred to as a variable interest entity ("VIE") pursuant to accounting guidance for consolidation if it
possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii)
the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual
economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be
consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that
variable interest holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that
most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits
from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable
interest in a VIE, a qualitative analysis is performed of the entity’s design, organizational structure, primary decision makers
and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that
could cause the primary beneficiary to change.
F-37
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
On January 4, 2013 and April 22, 2013, Laredo Midstream contributed $0.9 million and $2.3 million, respectively, to
Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company. Laredo Midstream holds 49% of
Medallion ownership units. Medallion, which was formed on October 31, 2012 and its wholly owned subsidiary, Medallion
Pipeline Company, LLC ("MPC"), a Texas limited liability company formed on September 9, 2013, were established for the
purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to
market. Laredo Midstream and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss
sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally,
Medallion requires a super-majority vote of 75% for all key operation and business decisions. The Company has determined
that Medallion is a VIE. However, Laredo Midstream is not considered to be the primary beneficiary of the VIE because Laredo
Midstream does not have the power to direct the activities that most significantly affect Medallion's economic performance. As
such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of net income
reflected in the consolidated statements of operations as "Income from equity method investee" and the carrying amount
reflected in the consolidated balance sheet as "Investment in equity method investee."
Laredo Midstream has committed to contribute an additional $25.7 million to Medallion in 2014 towards the
construction of a pipeline by MPC. The Company has recorded a capital contribution payable of $2.6 million related to the
fourth quarter cash requirements of the project and a payable of $0.9 million related to its minimum volume commitment to
Medallion, both of which are reported in the consolidated balance sheet as "Accrued payable - affiliates." The corresponding
expense related to the minimum volume commitment is reported on the consolidated statements of operations in the
"Transportation and treating - affiliates" line item.
N—Subsidiary guarantee
Laredo Midstream has fully and unconditionally guaranteed the 2019 Notes, the 2022 Notes and the Senior Secured
Credit Facility. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial
statements in order to quantify the assets, results of operations and cash flows of Laredo Midstream as a subsidiary guarantor.
The following condensed consolidating balance sheets as of December 31, 2013 and 2012, and condensed consolidating
statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2013,
2012 and 2011, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under
the equity method), financial information for the Laredo Midstream on a stand-alone basis (carrying any investment in
subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for
the Company on a condensed consolidated basis. Deferred income taxes for Laredo Midstream are recorded on Laredo's
statements of financial position, statements of operations and statements of cash flow as a flow-through entity for income tax
purposes. Laredo and Laredo Midstream are not restricted from making distributions.
F-38
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Condensed consolidating balance sheet
December 31, 2013
(in thousands)
Accounts receivable ...........................................................................
Other current assets............................................................................
Total oil and natural gas properties, net.............................................
Total pipeline and gathering assets, net .............................................
Total other fixed assets, net................................................................
Investment in subsidiaries and equity method investee.....................
Total other long-term assets...............................................................
Total assets.......................................................................................
Accounts payable ...............................................................................
Other current liabilities ......................................................................
Other long-term liabilities..................................................................
Long-term debt...................................................................................
Stockholders' equity...........................................................................
Total liabilities and stockholders' equity .........................................
Laredo
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
77,318
$
— $
— $
77,318
230,291
2,135,348
—
—
—
41,498
27,478
36,666
105,914
$ 2,613,015
$
12,216
231,008
45,997
1,051,538
1,272,256
$ 2,613,015
$
$
$
—
5,913
—
47,411
3,786
6,959
—
—
36,666
47,411
$
$
$
—
230,291
— 2,135,348
—
—
(36,666)
41,498
27,478
5,913
105,914
(36,666) $ 2,623,760
— $
16,002
—
237,967
—
45,997
— 1,051,538
(36,666)
1,272,256
(36,666) $ 2,623,760
Condensed consolidating balance sheet
December 31, 2012
Laredo
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
83,737
$
103
$
— $
83,840
53,597
2,031,938
—
16,661
60,652
86,976
$ 2,333,561
$
47,129
210,196
27,753
1,216,760
831,723
$ 2,333,561
$
$
$
—
—
65,292
—
—
—
65,395
1,543
3,200
—
—
60,652
65,395
$
$
$
53,597
—
— 2,031,938
65,292
16,661
—
—
(60,652)
—
—
86,976
(60,652) $ 2,338,304
48,672
— $
213,396
—
—
27,753
— 1,216,760
(60,652)
831,723
(60,652) $ 2,338,304
(in thousands)
Accounts receivable ...........................................................................
Other current assets............................................................................
Total oil and natural gas properties, net.............................................
Total pipeline and gathering assets, net .............................................
Total other fixed assets, net................................................................
Investment in subsidiaries..................................................................
Total other long-term assets...............................................................
Total assets.......................................................................................
Accounts payable ...............................................................................
Other current liabilities ......................................................................
Other long-term liabilities..................................................................
Long-term debt...................................................................................
Stockholders' equity...........................................................................
Total liabilities and stockholders' equity .........................................
F-39
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Condensed consolidating statement of operations
For the year ended December 31, 2013
(in thousands)
Total operating revenues....................................................................
Total operating costs and expenses....................................................
Income from operations...................................................................
Interest expense, net...........................................................................
Other, net............................................................................................
Income from continuing operations before income tax...................
Income tax (expense) benefit .............................................................
Income from continuing operations.................................................
Income (loss) from discontinued operations, net of tax ..................
Net income.......................................................................................
Laredo
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
665,172
$
8,824
$
455,972
209,200
(100,164)
84,861
193,897
(75,504)
118,393
(393)
118,000
$
3,673
5,151
—
2,268
7,419
997
8,416
1,816
$
10,232
$
(8,739) $
(8,739)
—
—
(10,232)
(10,232)
—
(10,232)
—
(10,232) $
665,257
450,906
214,351
(100,164)
76,897
191,084
(74,507)
116,577
1,423
118,000
Condensed consolidating statement of operations
For the year ended December 31, 2012
(in thousands)
Total operating revenues....................................................................
Total operating costs and expenses....................................................
Income from operations...................................................................
Interest expense, net...........................................................................
Other, net............................................................................................
Income from continuing operations before income tax...................
Income tax (expense) benefit .............................................................
Income from continuing operations.................................................
Income (loss) from discontinued operations, net of tax ..................
Net income.......................................................................................
Laredo
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
583,759
$
10,285
$
418,745
165,014
(85,513)
18,143
97,644
(33,969)
63,675
(2,021)
61,654
$
3,359
6,926
—
—
6,926
966
7,892
1,914
$
9,806
$
(10,150) $
(10,150)
—
—
(9,806)
(9,806)
—
(9,806)
—
(9,806) $
583,894
411,954
171,940
(85,513)
8,337
94,764
(33,003)
61,761
(107)
61,654
Condensed consolidating statement of operations
For the year ended December 31, 2011
(in thousands)
Laredo
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
Total operating revenues....................................................................
Total operating costs and expenses....................................................
Income from operations...................................................................
Interest expense, net...........................................................................
Other, net............................................................................................
Income from continuing operations before income tax...................
Income tax (expense) benefit .............................................................
Income from continuing operations.................................................
Income (loss) from discontinued operations, net of tax ..................
Net income.......................................................................................
$
$
506,430
308,541
197,889
(50,472)
21,182
168,599
(60,698)
107,901
(2,347)
105,554
$
$
7,189
2,558
4,631
—
—
4,631
1,086
5,717
1,925
$
7,642
$
(7,272) $
(7,272)
—
—
(7,642)
(7,642)
—
(7,642)
—
(7,642) $
506,347
303,827
202,520
(50,472)
13,540
165,588
(59,612)
105,976
(422)
105,554
F-40
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
Condensed consolidating statement of cash flows
For the year ended December 31, 2013
(in thousands)
Net cash flows provided by operating activities ................................
Net cash flows used in investing activities ........................................
Net cash flows provided by financing activities ................................
Net increase in cash and cash equivalents.......................................
Cash and cash equivalents at beginning of period...........................
Cash and cash equivalents at end of period.....................................
$
Laredo
359,198
(324,353)
130,084
164,929
33,224
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
15,763
(15,763)
—
—
—
$
(10,232) $
10,232
—
—
—
364,729
(329,884)
130,084
164,929
33,224
$
198,153
$
— $
— $
198,153
Condensed consolidating statement of cash flows
For the year ended December 31, 2012
(in thousands)
Net cash flows provided by operating activities ................................
Net cash flows used in investing activities ........................................
Net cash flows provided by financing activities ................................
Net increase in cash and cash equivalents.......................................
Cash and cash equivalents at beginning of period...........................
Cash and cash equivalents at end of period.....................................
$
Laredo
373,362
(937,337)
569,197
5,222
28,002
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
$
13,219
(13,219)
—
(9,805) $
9,805
—
376,776
(940,751)
569,197
$
33,224
$
— $
— $
—
—
—
—
5,222
28,002
33,224
Condensed consolidating statement of cash flows
For the year ended December 31, 2011
(in thousands)
Net cash flows provided by operating activities ................................
Net cash flows used in investing activities ........................................
Net cash flows provided by financing activities ................................
Net decrease in cash and cash equivalents ......................................
Cash and cash equivalents at beginning of period...........................
Cash and cash equivalents at end of period.....................................
$
Laredo
341,607
(704,318)
359,478
(3,233)
31,235
Laredo
Midstream
Intercompany
eliminations
Consolidated
company
$
$
10,111
(10,111)
—
(7,642) $
7,642
—
—
—
—
—
344,076
(706,787)
359,478
(3,233)
31,235
$
28,002
$
— $
— $
28,002
F-41
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
O—Subsequent events
1. Note offering
On January 23, 2014, Laredo completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior
unsecured notes due 2022 (the “Notes”), and entered into an Indenture (the “Indenture”) among Laredo, the Guarantor and
Wells Fargo Bank, National Association, as trustee. The Notes will mature on January 15, 2022 with interest accruing at a rate
of 5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July
15, 2014. The Notes are guaranteed on a senior unsecured basis by the Guarantor and certain of the Company’s future restricted
subsidiaries.
The Notes were issued pursuant to the Indenture in a transaction exempt from the registration requirements of the
Securities Act of 1933, as amended (the "Securities Act"). The Notes were offered and sold only to qualified institutional
buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under
the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial
purchasers’ discount and the estimated outstanding offering expenses. The Company will use the net proceeds of the offering
for general working capital purposes. As a result of the issuance of the Notes, the amount available for borrowings under the
Senior Secured Credit Facility was reduced to $812.5 million.
Laredo may redeem, at its option, all or part of the Notes at any time on and after January 15, 2017, at the applicable
redemption price plus accrued and unpaid interest to the date of redemption. In addition, Laredo may redeem, at its option, all
or part of the Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the
Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of
redemption. Further, before January 15, 2017, Laredo may on one or more occasions redeem up to 35% of the aggregate
principal amount of the Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings
at a redemption price of 105.625% of the principal amount of the Notes, plus accrued and unpaid interest to the date of
redemption, if at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after such
redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control
occurs prior to January 15, 2015, Laredo may redeem all, but not less than all, of the Notes at a redemption price equal to 110%
of the principal amount of the Notes plus any accrued and unpaid interest to the date of redemption.
In connection with the closing of the offering of the Notes, Laredo and the Guarantor entered into a Registration
Rights Agreement (the “Registration Rights Agreement”) with the several initial purchasers named in the Registration Rights
Agreement. Pursuant to the Registration Rights Agreement, Laredo and the Guarantor have agreed to use commercially
reasonable efforts to file a registration statement with the SEC relating to an offer to exchange the Notes for substantially
identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered
under the Securities Act so as to permit the exchange offer to be consummated within 365 days after the issuance of the Notes.
Under certain circumstances, Laredo and the Guarantor will be obligated to pay additional interest if they fail to comply with
their obligations to register the Notes within the specified time periods.
2. Additional contribution to Medallion
On February 5, 2014, Laredo Midstream contributed $11.3 million of its $25.7 million commitment to Medallion to
fund the construction of a pipeline by MPC. As of December 31, 2013, the Company had recorded a capital contribution
payable of $2.6 million related to this capital call.
3. Early termination of derivative contract
In February 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial
derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International
Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-
to-market accounting per the normal purchase normal sale exemption provided for under GAAP. Once modified to settle
financially in the unwind agreement, the contract ceased to qualify for the normal purchase normal sale exemption, therefore
requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these
contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity
trading business.
F-42
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2013, 2012 and 2011
4. New derivative contracts
Subsequent to December 31, 2013, the Company entered into the following new commodity contracts:
Aggregate
volumes
Swap
price
Contract period
Natural gas (volumes in MMBtu):
Swap(1)................................................
Swap(1)................................................
3,060,000
2,448,000
$
$
4.32
4.32
March 2014 - December 2014
March 2014 - December 2014
_____________________________________________________________
(1) These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation
period.
F-43
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2013, 2012 and 2011
P—Supplemental oil and natural gas disclosures
1. Costs incurred in oil and natural gas property acquisition, exploration and development activities
Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the periods
presented:
(in thousands)
Property acquisition costs:
For the years ended December 31,
2013
2012
2011
Proved .....................................................................................................................
Unproved.................................................................................................................
Exploration ................................................................................................................
Development costs(1)..................................................................................................
Total costs incurred...............................................................................................
$
9,652
$
16,925
$
27,087
48,763
3,693
93,266
654,452
839,118
—
—
62,888
660,922
$
739,954
$
953,002
$
723,810
__________________________________________________________________________
(1) The costs incurred for oil and natural gas development activities include $6.8 million, $7.4 million and $4.5 million, in
asset retirement obligations for the years ended December 31, 2013, 2012 and 2011, respectively.
2. Capitalized oil and natural gas costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion,
depreciation and impairment are presented below for the periods presented:
(in thousands)
Capitalized costs:
Proved properties ....................................................................................................
Unproved properties................................................................................................
For the years ended December 31,
2013
2012
2011
$ 3,276,578
$ 2,993,266
$ 2,083,015
208,085
3,484,663
159,946
3,153,212
117,195
2,200,210
Less accumulated depletion, depreciation and impairment ....................................
Net capitalized costs .............................................................................................
1,349,315
$ 2,135,348
1,121,273
$ 2,031,939
884,533
$ 1,315,677
The following table shows a summary of the oil and natural gas property costs not being amortized as of
December 31, 2013, by year in which such costs were incurred:
(in thousands)
2013
2012
2011
2010 and
prior
Total
Unproved properties ...................................................
$
124,588
$
67,370
$
8,249
$
7,878
$
208,085
Unproved properties, which are not subject to amortization, are not individually significant and consist of costs for
acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of wells being
evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is
unable to estimate when these costs will be included in the amortization calculation.
F-44
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2013, 2012 and 2011
3. Results of oil and natural gas producing activities
The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs)
are presented below for the periods presented:
(in thousands)
Revenues:
For the years ended December 31,
2013
2012
2011
Oil and natural gas sales..........................................................................................
$
664,844
$
583,569
$
506,255
Production costs:
Lease operating expenses........................................................................................
Production and ad valorem taxes ............................................................................
79,136
42,396
67,325
37,637
121,532
104,962
43,306
31,982
75,288
Other costs:
Depletion and depreciation .....................................................................................
Accretion of asset retirement obligation .................................................................
Income tax expense(1) ..............................................................................................
Results of operations.............................................................................................
$
227,992
1,475
112,984
200,861
$
237,130
1,200
83,686
156,591
$
171,517
616
93,180
165,654
__________________________________________________________________________
(1) Income tax expense above is computed utilizing the statutory rate.
4. Net proved oil and natural gas reserves - (unaudited)
Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the
Company's proved reserves as of December 31, 2013, 2012 and 2011. In accordance with SEC regulations, reserves as of
December 31, 2013, 2012 and 2011 were estimated using the unweighted arithmetic average first-day-of-the-month price for
the preceding 12-month period. The Company's reserves are reported in two streams; crude oil and natural gas. The economic
value of the natural gas liquids in the Company's natural gas is included in the wellhead natural gas price. The Company
emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those
of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.
The following table provides an analysis of the change in estimated quantities of oil and natural gas reserves, all of
which are located within the United States, for the periods presented.
Proved developed and undeveloped reserves:
Beginning of year....................................................................................................
Revisions of previous estimates ..............................................................................
Extensions, discoveries and other additions ...........................................................
Purchases of reserves in place.................................................................................
Sales of reserves in place ........................................................................................
Production ...............................................................................................................
End of year ..............................................................................................................
Proved developed reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
Proved undeveloped reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
F-45
Year ended December 31, 2013
Oil
(MBbl)
Gas
(MMcf)
MBOE
98,141
(17,956)
37,850
170
(1,220)
(5,487)
111,498
33,316
37,878
64,825
73,620
542,946
15,710
192,229
1,454
(165,289)
(34,348)
552,702
289,045
203,082
253,901
349,620
188,632
(15,338)
69,888
412
(28,768)
(11,211)
203,615
81,490
71,725
107,142
131,890
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2013, 2012 and 2011
Proved developed and undeveloped reserves:
Beginning of year....................................................................................................
Revisions of previous estimates ..............................................................................
Extensions, discoveries and other additions ...........................................................
Purchases of reserves in place.................................................................................
Production ...............................................................................................................
End of year ..............................................................................................................
Proved developed reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
Proved undeveloped reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
Proved developed and undeveloped reserves:
Beginning of year....................................................................................................
Revisions of previous estimates ..............................................................................
Extensions, discoveries and other additions ...........................................................
Purchases of reserves in place.................................................................................
Production ...............................................................................................................
End of year ..............................................................................................................
Proved developed reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
Proved undeveloped reserves:
Beginning of year....................................................................................................
End of year ..............................................................................................................
Year ended December 31, 2012
Oil
(MBbl)
Gas
(MMcf)
MBOE
56,267
(12,396)
57,391
1,654
(4,775)
98,141
21,762
33,316
34,505
64,825
601,117
(260,651)
232,418
9,210
(39,148)
542,946
248,598
289,045
352,519
253,901
156,453
(55,837)
96,127
3,189
(11,300)
188,632
63,195
81,490
93,258
107,142
Year ended December 31, 2011
Oil
(MBbl)
Gas
(MMcf)
MBOE
44,847
(1,124)
15,912
—
(3,368)
56,267
12,420
21,762
32,427
34,505
550,278
(47,296)
129,846
—
(31,711)
601,117
194,481
248,598
355,797
352,519
136,560
(9,006)
37,553
—
(8,654)
156,453
44,833
63,195
91,727
93,258
For the year ended December 31, 2013, the Company's negative revision of 15,338 MBOE of previously estimated
quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved
undeveloped locations and the net effect of redetermining 501 undeveloped locations. The 174 locations that were removed
were comprised of vertical Wolfberry and short horizontal laterals which were replaced with longer horizontal laterals to better
align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing,
performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December
31, 2013, consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new
proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations
in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian
Basin. The oil and natural gas reference prices used in computing our reserves as of December 31, 2013 were $93.52 per barrel
of oil and $3.57 per MMBtu of natural gas before price differentials.
For the year ended December 31, 2012, the Company's negative revision of 55,837 MBOE of previous estimated
quantities is primarily attributable to the removal of 50,845 MBOE due to lower natural gas prices and increased development
costs for vertical Granite Wash locations in the Anadarko Basin and shallow Wolfberry vertical locations in the Permian Basin.
Due to these factors, these locations became economically unattractive to develop and were replaced by new horizontal and/or
oil development opportunities. The balance of the negative revision of 4,993 MBOE is due to a combination of performance,
F-46
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2013, 2012 and 2011
pricing and other changes. Extensions, discoveries and other additions of 96,127 MBOE during the year ended December 31,
2012, consist of 26,235 MBOE primarily from the drilling of new wells during the year and 69,892 MBOE from new proved
undeveloped locations added during the year, which increased the Company's proved reserves. The latter consists of 67,200
MBOE attributable to 317 locations in our Permian Basin play and 2,692 MBOE attributable to six locations in our Anadarko
Granite Wash play. Purchases of minerals in place added 3,189 MBOE from acquisition of proved reserves in the Permian
Basin. The oil and natural gas reference prices used in computing our reserves as of December 31, 2012 were $91.21 per barrel
of oil and $2.63 per MMBtu of natural gas before price differentials.
For the year ended December 31, 2011, the Company's negative revision of 9,006 MBOE of previous estimated
quantities is primarily attributable to uneconomic proved undeveloped locations. Extensions, discoveries and other additions of
37,553 MBOE during the year ended December 31, 2011, consist of 14,709 MBOE primarily from the drilling of new wells
during the year and 22,844 MBOE from new proved undeveloped locations added during the year, which increased the
Company's proved reserves, the latter of which consists of 15,009 MBOE attributable to 155 vertical locations in our Permian
Basin play, 7,835 MBOE attributable to 47 vertical locations in our Anadarko Granite Wash play. The oil and natural gas
reference prices used in computing our reserves as of December 31, 2011 were $92.71 per barrel of oil and $3.99 per MMBtu
of natural gas before price differentials.
5. Standardized measure of discounted future net cash flows - (unaudited)
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to
present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account,
among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and
consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2013, 2012 and
2011 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period.
Estimated future production of proved reserves and estimated future production and development costs of proved reserves are
based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end
statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the
Company's oil and natural gas properties. Reference prices used, before differentials were applied were $93.52, $91.21 and
$92.71 per Bbl of oil and $3.57, $2.63 and $3.99 per MMBtu for December 31, 2013, 2012 and 2011, respectively. All
wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then
discounted at a rate of 10%.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as
follows for the periods presented:
(in thousands)
For the years ended December 31,
2013
2012
2011
Future cash inflows ................................................................................................
Future production costs..........................................................................................
Future development costs ......................................................................................
Future income tax expenses ...................................................................................
Future net cash flows...........................................................................................
10% discount for estimated timing of cash flows..................................................
Standardized measure of discounted future net cash flows ..............................
$ 13,337,798
(3,059,368)
(2,250,950)
(2,150,983)
5,876,497
(3,554,293)
$ 2,322,204
$ 11,636,926
(3,163,371)
(2,252,559)
(1,433,373)
4,787,623
(2,910,167)
$ 1,877,456
$ 8,856,906
(2,562,237)
(1,959,818)
(999,185)
3,335,666
(1,934,807)
$ 1,400,859
In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2013,
2012 and 2011 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic
average first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional
price differentials. Future costs of developing and producing the proved oil and natural gas reserves reported at the end of each
year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market
value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved
reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount
rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be
assigned to probable or possible reserves.
F-47
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2013, 2012 and 2011
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
are as follows for the periods presented:
(in thousands)
Standardized measure of discounted future net cash flows, beginning of year.........
Changes in the year resulting from:
Sales, less production costs .....................................................................................
Revisions of previous quantity estimates................................................................
Extensions, discoveries and other additions ...........................................................
Net change in prices and production costs..............................................................
Changes in estimated future development costs .....................................................
Previously estimated development costs incurred during the period......................
Purchases of reserves in place.................................................................................
Divestitures of reserves in place .............................................................................
Accretion of discount ..............................................................................................
Net change in income taxes ....................................................................................
Timing differences and other ..................................................................................
Standardized measure of discounted future net cash flows, end of year ..............
For the years ended December 31,
2013
2012
2011
$ 1,877,456
$ 1,400,859
$
869,982
(543,312)
(190,961)
1,166,481
(478,607)
(631,693)
1,287,952
(430,967)
(70,021)
529,041
566,034
(163,399)
207,818
—
194,921
(3,917)
137,510
25,041
—
176,996
(101,955)
(129,651)
$ 1,877,456
—
106,170
(176,165)
(37,634)
$ 1,400,859
313,947
921
89,396
7,604
(239,148)
234,852
(259,991)
(135,041)
$ 2,322,204
Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number
of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results.
Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data
are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions
as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts
estimated.
F-48
Laredo Petroleum, Inc.
Supplemental quarterly financial data
December 31, 2013, 2012 and 2011
Q—Supplemental quarterly financial data - (unaudited)
The Company's results from continuing operations by quarter for the periods presented are as follows:
(in thousands, except per share data)
Revenues ............................................................................................
Operating income...............................................................................
Net income .........................................................................................
Net income per common share:
Year ended December 31, 2013
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
163,705
$
177,296
$
170,840
$
153,416
44,505
1,409
57,414
35,812
57,420
12,543
55,012
68,236
Basic ................................................................................................
Diluted .............................................................................................
$
$
0.01
0.01
$
$
0.28
0.27
$
$
0.09
0.09
$
$
0.48
0.48
(in thousands, except per share data)
Year ended December 31, 2012(1)
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Revenues ............................................................................................
Operating income...............................................................................
Net income (loss) ...............................................................................
Net income (loss) per common share:
Basic ................................................................................................
Diluted .............................................................................................
$
$
$
149,012
55,145
26,235
0.21
0.20
$
$
$
139,715
41,689
30,975
0.24
0.24
$
$
$
$
143,835
37,206
(7,384)
151,332
37,900
11,828
(0.06) $
(0.06) $
0.09
0.09
______________________________________________________________________________
(1) The results of operations of the Pipeline Assets, which are a component of the Anadarko Basin Sale, are presented as
results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has
reclassified the financial results and the related notes for all prior periods presented to reflect these operations as
discontinued.
F-49
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Highlights
Corporate Information
Total Proved Reserves
(MMBOE)
Proved Developed Reserves
(MMBOE)
Senior Officers
R ANDY A. FOUTCH | CHAIR MAN & CHIEF EXECUTIVE OFFICER
Randy A. Foutch
Chairman & Chief
Executive Officer
Jay P. Still
President & Chief
Operating Officer
Richard C.
Buterbaugh
Executive Vice
President & Chief
Financial Officer
Patrick J. Curth
Senior Vice
President
Exploration & Land
Kenneth E.
Dornblaser
Senior Vice
President & General
Counsel &
Secretary
Daniel C. Schooley
Senior Vice
President
Midestream &
Marketing
Proved Developed Reserves
Proved Developed Reserves
Independent Directors
Senior Officers
Peter R. Kagan
Warburg Pincus, Managing Director
Randy A. Foutch
Chairman & Chief Executive Officer
Jay P. Still
Director, President &
Chief Operating Officer
Richard C. Buterbaugh
Executive Vice President &
Chief Financial Officer
Patrick J. Curth
Senior Vice President,
Exploration & Land
Kenneth E. Dornblaser
Senior Vice President &
General Counsel & Secretary
Daniel C. Schooley
Senior Vice President
Midstream & Marketing
James R. Levy
Warburg Pincus, Managing Director
B.Z. (Bill) Parker
Phillips Petroleum Company,
Former Executive Vice President
Pamela S. Pierce
Ztown Investments, Inc., Partner
Ambassador Francis Rooney
Rooney Holdings, Inc. &
Manhattan Construction Group, Chief
Executive Officer
Dr. Myles W. Scoggins
Colorado School of Mines, President
Edmund P. Segner, III
EOG Resources, Former President,
Chief of Staff & Director
Donald D. Wolf
Quantum Resources Management,
LLC, Chairman
Directors
Randy A. Foutch
Chairman & Chief Executive Officer
Jay P. Still
Director, President &
Chief Operating Officer
Stock Transfer Agent
American Stock Transfer and
Trust Company
6201 15th Avenue
Brooklyn, NY 11219
(800) 937-5449
Independent Auditors
Grant Thornton LLP
2431 East 61st Street, Suite 500
Tulsa, OK 74136
(918) 877-0800
Third-Party Reserve Engineers
Ryder Scott Company, L.P.
Petroleum Consultants
TBPE Registered Engineering
Firm F-1580
1100 Louisiana, Suite 3800
Houston, TX 77002
(713) 651-9191
Legal Counsel
Akin Gump Strauss Hauer & Feld LLP
1111 Louisiana Street, 44th Floor
Houston, TX 77002
(713) 220-5800
Stock Exchange Listing
Laredo’s common shares are
publicly traded on the NYSE
under the symbol “LPI.”
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C or por a t e Prof i le
Laredo Petroleum is an independent energy company headquartered in
Tulsa, Oklahoma. Laredo’s business strategy is focused on the exploration,
development and acquisition of oil and natural gas properties primarily in
the Permian region of the United States.
A re a s of Ope r a t ion
Our activities are primarily focused on the multi-zone stacked-horizontal
development of our Permian Basin acreage position located in West Texas.
These plays are characterized by high oil and liquids-rich natural gas con-
tent, multiple target horizons, extensive production histories, long-lived
reserves, high drilling success rates and significant resource potential.
PER MI A N BASIN
(WOLFBER RY/WOLFCA MP/CLINE)
■ Oil and liquids-rich natural gas
■
Extensive vertical and horizontal drilling program
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Laredo Petroleum, Inc.
15 W. Sixth Street, Suite 900
Tulsa, Oklahoma 74119
Office 918.513.4570
www.laredopetro.com
L A R EDO PETROLEUM | 2013 A NNUA L R EPORT
Laredo is headquartered in Tulsa, OK
with offices in Dallas and Midland, TX
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