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L A R EDO PETROLEUM | 2014 A NNUA L R EPORT
C or por a t e Prof i le
Laredo Petroleum is an independent energy company with headquarters in
Tulsa, Oklahoma. Laredo’s business strategy is focused on the acquistion,
exploration, and development of oil and natural gas properties primarily in the
Permian Basin in West Texas.
PER MI A N BASIN
(WOLFBER RY/WOLFCA MP/CLINE)
■ Oil and liquids-rich natural gas
■ Extensive vertical and horizontal drilling program
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 content, multiple target
horizons, extensive production histories, long-lived reserves,
high drilling success rates and significant resource potential.
Laredo is headquartered in Tulsa, OK with an office in Midland, TX
Dear Stockholders:
In 2014, Laredo built upon our strategy to fully and efficiently
develop the world-class resource base that we have identified in
our Permian Basin acreage. Targeting multi-zone development
of the Upper, Middle and Lower Wolfcamp and Cline shale
zones on our highly contiguous acreage base, we grew production
and reserves to record levels for the Company. Production grew
to approximately 11.7 million barrels of oil equivalent on a
two-stream basis, an increase of approximately 29% when
adjusted for the Anadarko Basin divestiture. Proved reserves
grew to 247.3 million barrels of oil equivalent on a two-stream
basis, an increase of approximately 21% and we replaced
approximately 470% of production with the drill-bit.
Our 2014 growth was facilitated by investing in the
infrastructure needed to accommodate the decades of drilling
that we have identified and now serves as a foundation for
further, efficient development. When we began building our
Garden City acreage position, we anticipated targeting the
thickest sections of resource for horizontal development. As
additional zones were delineated, we recognized that developing
water to and from the leasehold. Laredo’s contiguous, high
the entire resource would require an integrated approach of
working interest acreage base makes it possible to invest in the
drilling multiple horizontal wells in the same location,
infrastructure. This infrastructure, which we call production
completing them simultaneously and having the infrastructure
corridors, will enable us to efficiently drill a large number of
necessary to transport the large volumes of oil, natural gas and
horizontal wells in a concentrated area in order to develop the
initial four identified zones, and any others that we delineate.
Laredo’s 2014 drilling plan was successful in implementing all of
these concepts. Approximately 70% of our completed horizontal
wells were on multi-well pads targeting two, three or four zones.
We continued construction of our first production corridor
which is seven miles long and can accommodate the
approximately 450 horizontal wells needed to fully develop the
initial four zones that have been de-risked on the 21 square miles
it serves. We also began construction on three additional
production corridors and invested in the Medallion Pipeline,
which transports our oil to Colorado City and enables
optionality to access multiple markets for our oil and avoid the
congested Midland market.
Similarly, Laredo has always employed strategies that provide
options to mitigate the risks of commodity price fluctuations.
We have limited the majority of our contracts with service
providers to one year or less, enabling us to rapidly reduce the
number of drilling rigs we employ without incurring substantial
costs. Additionally, we have traditionally hedged a meaningful
percentage of our anticipated oil and natural gas production for
an extended period. As a result, we have hedged almost all of
our anticipated oil production for 2015 at a weighted-average
floor price of approximately $81 per barrel. For 2016, we have
hedged more than one-half of our anticipated oil production at
approximately $82 per barrel and approximately one-third of our
Highlights
120
100
80
60
40
20
Proved Developed Reserves
E
O
B
M
M
250
0
2010
2011
2012
2013
2014
Other Reserves
Total Proved Reserves
Permian Reserves
200
150
100
50
0
2010
2011
2012
2013
2014
development of our multi-decade drilling inventory to enhance
value for our stockholders.
Our long-term strategy for maximizing the value of our
Permian-Garden City asset for our stockholders has not changed.
We are in the enviable position of having a highly contiguous
acreage base with multiple zones to target with horizontal
drilling. While the current commodity price environment
presents short-term challenges, we will continue to move
forward with our plans to develop the entire asset in an efficient
manner. We expect to continue to make investments in our
production corridors and the Medallion Pipeline system, as
appropriate, and to drill in the most efficient and prudent
manner in any given commodity price environment to enhance
R ANDY A. FOUTCH | CHAIR MAN & CHIEF EXECUTIVE OFFICER
our long-term value.
anticipated oil production in 2017 at approximately $77 per
barrel. We have taken a similar approach for our liquids-rich
natural gas production, hedging approximately 70% and 50% of
anticipated production for 2015 and 2016, respectively, at a
weighted-average floor price of $3.00 per MMBtu.
Other PDP Reserves
While we faced many challenges in 2014, the commitment and
contributions of our employees to the Company were exemplary.
Their dedication to our core concepts of integrity, stewardship,
respect, teamwork and success carried us through 2014 and into
a very bright future. I would also like to recognize the efforts of
While we do not know what oil prices will do in the future, we
Permian PDP Reserves
our Board of Directors. As always, their insight and guidance
manage the risks associated with oil and gas exploration and
proved invaluable. Most of all, we thank our stockholders and
development, and the business practices we have employed are
appreciate the trust they place in us to guide and grow their
enabling us to take a flexible approach to manage through a
company.
potentially extended, difficult price environment. In the short
term, our solid hedge position is providing stability to our cash
flow from operations to help fund a drilling program which we
expect to hold our core acreage position. This program is
expected to generate a moderate growth rate while operating
closer to our internally generated cash flow. However, we
continue to focus on opportunities that could accelerate
Randy A. Foutch
Chairman & Chief Executive Officer
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, 2014
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 900
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 $2,573.5 million on
June 30, 2014, based on $30.98 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 23, 2015: 143,263,488
Documents Incorporated by Reference:
Portions of the registrant's definitive proxy statement for its 2015 Annual Meeting of Stockholders, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2014, are incorporated by reference into Part III of this report for the
year ended December 31, 2014.
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
7
30
46
46
46
46
47
49
52
76
78
78
78
81
82
82
82
82
82
83
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.
"Earth Model"—An integrated workflow process combining geoscience and engineering data with multivariate statistics.
"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 differ 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, water, 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.
3
"MMBtu"—One million British thermal units.
"MMcf"—One million cubic feet of natural gas.
"Natural gas liquids ("NGL")"—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 that 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
locations 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.
"Three stream"—Production or reserve volumes of oil, natural gas liquids and natural gas, where the natural gas liquids
have been removed from the natural gas stream and the economic value of the natural gas liquids is separated from 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.
"Wolfberry"—A general industry term that applies to the vertical stratigraphic interval that can include the shallow
Spraberry formation to the deeper Woodford formation throughout the Permian Basin.
"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 or other 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 volatility of oil and natural gas prices;
changes in domestic and global production, supply and demand for oil and natural gas;
the continuation of restrictions on the export of domestic crude oil and its potential to cause weakness in domestic
pricing;
the potentially insufficient refining capacity in the U.S. Gulf Coast to refine all of the light sweet crude oil being
produced in the United States, which, coupled with the export limitations noted above and a continuing increase in
light sweet crude oil production, could result in widening price discounts to world crude prices and potential shut-in of
production due to lack of sufficient markets;
the ongoing instability and uncertainty in the U.S. and international financial and consumer markets that could
adversely affect the liquidity available to us and our customers and adversely affect the demand for commodities,
including oil and natural gas;
regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to
access and dispose of water used in these operations;
legislation or regulations that prohibit or restrict our ability to drill new allocation wells;
our ability to execute our strategies, including but not limited to our hedging strategies;
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;
changes in the regulatory environment and changes in international, legal, political, administrative or economic
conditions;
drilling and operating risks, including risks related to hydraulic fracturing activities;
risks related to the geographic concentration of our assets;
capital requirements for our operations and projects;
our ability to access additional borrowing capacity under our Senior Secured Credit Facility (as defined below) or
other means of providing capital and liquidity;
our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and to generate future
profits;
the availability and costs of drilling and production equipment, labor and oil and natural gas processing and other
services;
the availability of sufficient pipeline and transportation facilities and gathering and processing capacity;
our ability to comply with federal, state and local regulatory requirements;
restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures
governing our Senior Unsecured Notes (as defined below), as well as debt that could be incurred in the future, and;
our ability to recruit and retain the qualified personnel necessary to operate our business.
5
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.
6
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. On October 24, 2014, Laredo formed Garden City Minerals, LLC, a Delaware limited liability company
("GCM"), as a wholly-owned subsidiary. 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 subsidiaries, Laredo Midstream Services, LLC and GCM, as of the completion of our internal corporate
reorganization and thereafter, as applicable.
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.
Except where the context indicates otherwise, amounts, numbers, 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 acquisition, exploration and development of oil and natural
gas properties primarily in the Permian Basin in West Texas. 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, 2014, we had assembled 196,683 net acres in the Permian Basin and had total proved
reserves, presented on a two-stream basis, of 247,322 MBOE.
The Permian Basin is comprised of several distinct geological provinces, including: the Midland Basin to the east, the
Delaware Basin to the west and the Central Platform in the middle. Our primary development and production fairway is located
on the east side of the Midland Basin, 35 miles east of Midland, Texas, and extends approximately 20 miles wide (east/west)
and 85 miles long (north/south) in Howard, Glasscock, Reagan, Sterling, Irion and Tom Green counties and is referred to in this
Annual Report as the "Permian-Garden City" area. As of December 31, 2014, we held 155,405 net acres in 360 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 multiple producing formations that
partially make up the vertical Wolfberry interval. To date, this includes four identified targets for horizontal drilling (Upper,
Middle, and Lower Wolfcamp and Cline formations). From our inception in 2006 through December 31, 2014, we have drilled
and completed (i.e., the particular well is flowing) 174 horizontal wells in these four target zones and 933 vertical wells in the
Wolfberry interval. We have completed 75 horizontal Upper Wolfcamp wells, 31 horizontal Middle Wolfcamp wells, 21
horizontal Lower Wolfcamp wells and 47 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 24 to 29 stages) as we continue the
optimization of our completion techniques. As of February 25, 2015, we are drilling five wells in our Permian-Garden City
area.
7
As illustrated in the following table, as a result of our drilling activity through 2014 coupled with our technical data
and well performance, we believe that, as of December 31, 2014, we have de-risked the horizontal development potential for
the equivalent of 400,000 net acres from these four zones, as well as our entire Permian-Garden City acreage position for
vertical development. 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.
Upper Wolfcamp................................................................................................................................
Middle Wolfcamp..............................................................................................................................
Lower Wolfcamp...............................................................................................................................
Cline ..................................................................................................................................................
Total.................................................................................................................................................
Horizontal development
de-risked net acreage as of
December 31, 2014
90,000
90,000
83,000
137,000
400,000
In addition, in the third quarter of 2014, we successfully drilled our first well in the Canyon formation. It is anticipated
that a delineation Canyon well will be drilled in the first quarter of 2015. We plan to continue to gather data and drill additional
wells in zones other than our initial four target zones.
In 2015, as reflected in our capital drilling budget, we plan to continue drilling and collecting technical data across our
Permian-Garden City acreage. We expect our Permian-Garden City acreage to continue to be the primary driver of our growth
in reserves, production and cash flow for the foreseeable future.
Laredo was founded in October 2006 by our Chairman and Chief Executive Officer, Randy 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 (as such terms are defined below). In
December 2013, we completed a separate internal corporate reorganization, and in October 2014, we created GCM as a new
wholly-owned subsidiary for the primary purpose of holding certain of our mineral interests. See "—Corporate history and
structure."
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.
Since our inception, we have grown our reserves, production and cash flow primarily through our drilling program
coupled with select strategic acquisitions, including our July 2011 acquisition of Broad Oak. Our net proved reserves were
estimated at 247,322 MBOE on a two-stream basis as of December 31, 2014, of which 43% are classified as proved developed
reserves and 57% are attributed to oil reserves. For all periods prior to January 1, 2015, our reserves and production are
reported in two streams: crude oil and liquids-rich natural gas. This means the economic value of the natural gas liquids in our
natural gas is included in the wellhead natural gas price. Effective January 1, 2015, we will report our production volumes on a
three-stream basis, which separately reports natural gas liquids from crude oil and natural gas. 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.
8
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, 2014, and average daily production presented on a two-stream basis for the year ended
December 31, 2014. Based on estimates in the report prepared by Ryder Scott, we operated wells that represent 98% of the
economic value of our proved developed oil and natural gas reserves as of December 31, 2014.
As of December 31, 2014
Estimated net
proved reserves(1)(2)
Producing
wells
MBOE
247,313
9
247,322
% of
total reserves
% Oil
Net
acreage
Gross
Net
100%
57% 196,683
1,279
1,123
—% 100%
44,949
1
1
100%
57% 241,632
1,280
1,124
Year ended
December 31, 2014
average daily
production (BOE/D)
32,128
6
32,134
Permian Basin ..............................
Other Properties............................
Total ...........................................
_____________________________________________________________________________
(1) 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 $91.48 per Bbl for oil and $4.25 per MMBtu for natural gas for the 12 months ended December 31, 2014.
(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, 2014 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 $6.39 per Mcf.
Our net average daily production for the year ended December 31, 2014 was 32,134 BOE/D, 59% of which was oil
and 41% of which was primarily liquids-rich natural gas.
Reflecting the sharp decline in oil and natural gas prices in the second half of 2014, we reduced our 2015 planned
capital program. In connection with the reduced capital program, we approved a capital budget of $525 million for 2015;
however, this budget is based on 2014 service cost rates and may be adjusted if service rates decline in 2015. Substantially all
of the planned capital budget is anticipated to be invested in the Permian-Garden City area. We intend to continue to drill
vertical wells that we believe will provide attractive economics and/or for the purpose of holding prospective targeted zones.
Because of the stacked multiple-zone horizontal targets underlying our acreage, we are continuing to refine the optimal
geometry relative to horizontal well spacing, 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. We are
increasingly allocating a greater percentage of both capital and human resources towards our horizontal drilling activity, which
generally produces more attractive economics than our vertical program.
In connection with our reduced capital budget, we are decreasing the number of horizontal and vertical drilling rigs
working our properties in the Permian-Garden City area. On December 31, 2014, we had a total of nine operated drilling rigs
consisting of six rigs drilling horizontal wells and three rigs drilling vertical wells. Our current drilling schedule anticipates that
we will drop to two horizontal rigs and one vertical rig by May 1, 2015, and for the entire year of 2015, we expect to average
2.4 horizontal rigs and 1.5 vertical rigs.
While our horizontal drilling program will be focused primarily on developing the four initial zones already identified
in the liquids-rich Wolfcamp and Cline intervals underlying our Permian-Garden City area, we believe, based on petrophysical
analysis and preliminary drilling results, additional potential may exist in both shallower and deeper formations, including the
Spraberry and Canyon. Additional testing of these new targeted intervals, as well as other identified intervals, will continue in
2015, but is not anticipated to be a significant component of our drilling program.
The timing of drilling our potential locations is influenced by several factors, including commodity prices, capital
requirements and availability, the Texas Railroad Commission ("RRC") well-spacing requirements and the continuation of the
positive results from our ongoing development drilling program.
To more efficiently deploy our capital, we anticipate allocating an increased percentage of our reduced capital budget
to drilling activities, and we will actively seek to decrease our unit lease operating and general & administrative expenses. On
January 20, 2015, we announced the termination of approximately 75 employees Company-wide and the closing of our Dallas,
Texas area office. We also released 24 contract personnel. See Note 16.b to our audited consolidated financial statements
9
included elsewhere in this Annual Report. In addition, we anticipate decreases in service costs as a result of the recent
commodity price decline.
Laredo has built an extensive proprietary technical database that includes 838 square miles of 3D seismic, 27
microseismic surveys, more than 8,000 open and cased hole logging suites including 120 dipole sonic logs, 3,700 feet of
proprietary whole cores in 14 wells, 715 sidewall cores, 56 single zone tests and 42 production logs. Laredo's strategic interest
in assembling a rich database is directed at efficiently accelerating the delineation of "de-risked" acreage of resource plays in
the Permian-Garden City area and maximizing value creation during the field development phase.
A key component of our reservoir characterization process is internally referred to as the "Earth Model", which
represents an integrated workflow combining geoscience and engineering data with multivariate statistics. The workflow
employed in the Earth Model process differs from the more conventional earth science/engineering approach in that the Earth
Model involves parallel workflows, multivariate statistics and significant input from multiple disciplines. The goal of the Earth
Model is to develop a predictive three dimensional model that can forecast production rates through associating empirical
subsurface data with proved methods.
We have been developing the Earth Model process over a period of three years, covering an area where more than 80
calibrated pre-stack inversion attributes have been extensively developed and tested to determine fundamental controls on
reservoir performance. The four major components of the the Earth Model are (i) geophysical data (i.e., 3D seismic and micro-
seismic surveys), (ii) logs (i.e., conventional open-hole, dipole sonic, and in-house core calibrated petrophysical logs), (iii)
cores (both whole and sidewall) and (iv) production history, production logs and single-zone tests. By integrating data that
represent mechanical properties, natural fractures, reservoir properties and lithology within a multivariate statistical model, we
were able to develop a relationship to production with an 85% correlation coefficient for the initial four primary targets (Upper
Wolfcamp, Middle Wolfcamp, Lower Wolfcamp, and Cline).
We consider the Earth Model a potentially significant tool in planning development wells in laterally and vertically
complex geology by optimizing landing points and geo-steering targets while integrating vertical and lateral spacing
considerations.
We estimate 90% of our horizontal wells drilled in 2015 will utilize at least some aspects of the Earth Model,
demonstrating evolution from a calibrated backward-looking model into a primary tool for development and delineation well-
planning. If our preliminary applications of the Earth Model are replicated in forward-looking well-planning, we anticipate that
the Earth Model may positively impact our ability to increase initial production rates and estimated ultimate recoveries.
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. ("Holdings"), with Holdings 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 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 Holdings. Holdings
completed an IPO of its common stock on December 20, 2011. As of December 31, 2014, Warburg Pincus owned 40.3% 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 then 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 Midstream"). Laredo Petroleum,
Inc., a wholly-owned subsidiary of 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."
10
On October 24, 2014, GCM, a wholly-owned subsidiary of Laredo Petroleum, Inc., was formed primarily to hold
certain mineral interests owned by the Company. The creation of GCM, the Corporate Reorganization, the IPO and the Internal
Consolidation are discussed in Note 1 to our audited consolidated financial statements included elsewhere in this Annual
Report.
Laredo Petroleum, Inc. is the borrower under our Fourth Amended and Restated Credit Senior Secured Credit Facility
(as amended, the "Senior Secured Credit Facility"), as well as the issuer of our $550 million 9 1/2% senior unsecured notes due
2019 (the "2019 Notes") issued in January and October 2011, our $500 million 7 3/8% senior unsecured notes due 2022 issued
in April 2012 (the "May 2022 Notes") and our $450 million 5 5/8% senior unsecured notes due 2022 issued in January 2014
(the "January 2022 Notes"). We refer to the 2019 Notes, the May 2022 Notes and the January 2022 Notes collectively as the
"Senior Unsecured Notes." Our subsidiaries, Laredo Midstream and GCM, are guarantors 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:
Continue to develop our Permian-Garden City acreage. As of December 31, 2014, we had 155,405 net acres in the
Permian-Garden City area. As of such date, we believe we have established the economic horizontal potential of 90,000 net
acres for horizontal Upper Wolfcamp drilling, 90,000 net acres for horizontal Middle Wolfcamp drilling, 83,000 net acres for
Lower Wolfcamp drilling and 137,000 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, and in the future will attempt to de-risk acreage for other
zones. We anticipate the opportunities afforded in our Permian-Garden City area will support consistent, predictable, annual
growth in reserves, production and cash flow.
Our Permian-Garden City acreage will likely be the primary driver of our growth in reserves, production and cash
flow for the foreseeable future. We believe we have confirmed the vertical development potential of our entire Permian-Garden
City acreage position (utilizing more than 900 vertical wells across our acreage position, of which more than 400 have been
drilled through the Wolfcamp, Cline and Atoka formations). Based on 174 horizontal wells drilled and completed as of
December 31, 2014, coupled with our technical data and well performance from all four initially targeted zones, we categorize
the equivalent of 400,000 net acres as de-risked for commercial horizontal development. We further believe this largely
contiguous de-risked acreage position provides a multi-decade development inventory to support consistent growth of reserves,
production and cash flow. With the assistance of our expanded infrastructure and midstream capabilities, we are implementing
a systematic multi-well pad development drilling program that will enable us to optimize spacing, minimize drainage
interference and maximize our frac efficiency. 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. In 2014, we continued
to implement our stacked lateral program (up to four different zones) with multiple tests in several areas of our acreage. Our
objectives with the stacked lateral program are to optimize the vertical distance between the laterals, minimize interference,
enhance frac efficiency and optimize scheduling of rig operations on multi-well pads. We anticipate that these improvements
will result in efficiency gains and potentially lead to better rates of return on our wells. Our development 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 all of our targeted zones in the Permian-Garden City acreage. Going forward, we plan to
continue drilling and collecting technical data across our Permian-Garden City acreage position.
Utilize our infrastructure to more efficiently develop our acreage. In conjunction with our development program,
Laredo Midstream has built, and is continuing to build, midstream facilities to enhance our production capabilities. Laredo
Midstream has constructed crude oil truck stations in Glasscock and Reagan counties, Texas, and for a portion of our
production, our system provides us with multiple sales outlets through interconnecting pipelines, potentially minimizing the
risks of both shut-ins awaiting pipeline connection and curtailment of downstream pipelines. Laredo Midstream has installed
(or is in the process of installing) four production corridors across portions of the Permian-Garden City area to provide for the
movement of oil, natural gas and water to and from our drilling and production operations. We anticipate that these corridors
will provide the delivery and takeaway capacity necessary to support hundreds of wells to be drilled in these areas. The natural
gas lines in these corridors provide for the gathering of produced natural gas, the delivery of natural gas to fuel drilling rigs in
the corridor and the high-pressure gas lift for producing wells in the corridor. Similarly, the water lines in the corridor provide
for the delivery of fresh water and recycled water to wells for completion on the corridors. In one of our production corridors,
Laredo Midstream constructed a water treatment facility that will be used to process flowback and produced water and recycle
that water for use in completion operations for the more than 400 wells that can be accommodated by the facilities in this
corridor. We believe this will reduce both the fresh water requirements for our operations and the volume of water that must be
11
sent to disposal facilities.
Additionally, through Laredo Midstream and our joint venture entity, Medallion Gathering & Processing, LLC
("Medallion"), a Texas limited liability company, we have built or contributed to the construction of an extensive oil gathering
system and pipeline infrastructure spanning more than 220 miles from the Midland Basin to Colorado City, Texas. This
network enables us to avoid costs associated with trucking or other transportation options while maintaining our flexibility to
sell oil in multiple markets.
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 proprietary 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 174 completed horizontal wells in all three Wolfcamp zones and the Cline shale zones.
We intend to continue to make upfront investments in expanding our technical database only in those areas where the
Earth Model indicates additional data is required. Currently, the Earth Model has been completed on approximately the
southern third of our Permian-Garden City acreage. It is anticipated that by the end of 2015 a majority of our acreage will be
evaluated utilizing this process to some extent. The Earth Model is an evolving workflow that can be re-calibrated as new
drilling results, petrophysical data and 3D seismic reprocessing are received over time.
Maintain financial flexibility through continued improvements in operational and cost efficiencies, prudent drilling
and measured growth. In the current commodity price environment, we are focused on efficient and prudent capital
allocation. We continue to focus on oil and liquids-rich drilling opportunities, which 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 are decreasing the number of drilling rigs working our
acreage in order to conserve capital and reduce our cash outspend. We are actively seeking to decrease our lease operating and
general & administrative expenses. On January 20, 2015, we announced the termination of approximately 75 employees
Company-wide and the closing of our Dallas, Texas area office. We also released 24 contract personnel. See Note 16.b to our
audited consolidated financial statements included elsewhere in this Annual Report. In addition, based on the current
commodity environment, we are actively negotiating lower service cost contracts.
We continue to seek operational efficiencies throughout the Company, including through our development plan. 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 horizontally and vertically, 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 where we
believe it will result in solid economic returns, hold acreage and/or de-risk additional acreage for all zones. Our management
team is focused on continuous improvement of our operating efficiencies and has significant experience in managing
development programs during periods of lower commodity prices. We are the operator for 88% of our Permian-Garden City
wells, which enables 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-decade 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, including
transactions that increase our working interest ownership percentage in areas where we already have leases. As we have
previously announced, we have been in discussions with interested parties regarding a potential joint development opportunity
involving a portion of our Permian-Garden City acreage. There is no assurance that a transaction will be consummated.
Proactively manage risk to limit downside. We continually monitor and control our business and operating risks
through various risk management practices, including employing prudent safety and environmental practices, seeking a flexible
financial profile, making upfront investment in research and development as well as data acquisition, seeking multiple sales
outlets, minimizing long-term contracts and maintaining an active commodity hedging program.
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-decade drilling inventory. From our inception in
2006 through December 31, 2014, we have completed 933 gross vertical and 178 gross horizontal wells with a success rate of
99% in our Permian-Garden City area. The 178 gross horizontal wells are comprised of 174 wells in the Upper, Middle and
12
Lower Wolfcamp and Cline shales, one well in the Spraberry, one well in the Canyon and two wells in the Strawn. Based on
our drilling results through December 31, 2014, we believe we have confirmed the economic horizontal development potential
of the equivalent of 400,000 net acres from the four initial zones that includes 90,000 net acres in the Upper Wolfcamp, 90,000
net acres in the Middle Wolfcamp, 83,000 net acres in the Lower Wolfcamp and 137,000 net acres in the Cline shale. We
believe these locations provide a multi-decade drilling inventory supporting future growth in reserves, production and cash
flow.
Significant hedges in place to guard against price volatility. We engage in an active hedging program in an effort to
decrease the volatility of our cash flow due to changes in commodity prices. We currently have hedges in place for oil that
represent more than 95% of anticipated production in 2015 with a weighted-average floor price of $80.99 per Bbl, and hedges
in place for natural gas and natural gas liquids that represent 63% of anticipated production in 2015 at a weighted-average floor
price of $3.00 per MMBtu. For 2016, we have hedges in place for 4.1 million barrels of oil with a weighted-average floor price
of $81.84 per Bbl and hedges for natural gas for 18.7 million MMBtu with a weighted-average floor price of $3.00 per MMBtu.
Further, at December 31, 2014, for 2017, we had hedges in place for 2.3 million barrels of oil with a weighted-average floor
price of $80.00 per barrel. Subsequent to December 31, 2014, we entered into hedges for an additional 365 thousand barrels of
oil at a weighted-average floor price of $60.00 per Bbl for 2017. This brings our total 2017 hedged oil volume to 2.6 million
barrels with a weighted-average floor price of $77.22. We believe that the price certainty associated with these hedges allows us
to better plan and forecast our upcoming capital and operational spending.
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, as of December 31, 2014, includes
838 square miles of proprietary/licensed 3D seismic (covering 95% of such acreage position), 303 proprietary petrophysical
logs (fully core calibrated), and more than 8,000 historical open and cased hole logs from the general area. We have also run
120 dipole sonic logs, 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
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. We have utilized this information in the creation of the Earth
Model, which we believe will assist us in optimizing our well results. Another important objective of the Earth Model and our
information database is 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, 2014, based on a report prepared by Ryder Scott. We believe that maintaining operating
control permits us to better pursue our strategy of enhancing returns through operational and cost efficiencies and maximizing
ultimate hydrocarbon recoveries 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, owns and operates more than
175 miles of pipeline in our natural gas gathering systems in the Permian Basin as of December 31, 2014. Additionally, through
our joint venture with Medallion, we have access to more than 220 miles of oil gathering systems and pipelines connected to
Colorado City, Texas. These systems and flowlines provide greater operational efficiency and potentially lower price
differentials for our production and enable us to coordinate our activities to connect our wells to market upon completion with
minimal days waiting on pipeline. Laredo Midstream has built, and is continuing to build, production corridors on our
contiguous acreage position that we believe increase efficiencies in oil and gas takeaway capacity, water supply and field level
operations.
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 historical institutional investor, as well as other 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 current properties are located in the prolific Permian Basin 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
13
repeatable results through internally generated horizontal and vertical drilling programs. We expect our Permian-Garden City
acreage, which is characterized by a high oil content, to be the primary driver of our growth in reserves, production and cash
flow 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 196,683 net acres as of December 31, 2014, 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
located 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, Irion and Tom Green counties. As of December 31, 2014, we held
155,405 net acres in 360 sections in the Permian-Garden City area with an average working interest of 96% in all Laredo-
operated producing wells.
During 2014, we continued to expand our horizontal development program for the Wolfcamp and Cline shales. Our
results indicate that our acreage in the Permian-Garden City area can be produced horizontally simultaneously out of multiple
zones. 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 primary horizontal targets in the Permian-Garden City area. Additional drilling has been
done and will continue to determine what other formations, if any, hold economically viable horizontal development
opportunities. During 2014, we drilled and completed 78 horizontal wells in our initial four target primary zones and now have
a total of 174 horizontal wells, confirming production and attractive returns from all four primary zones. Today, we are
continuing our drilling focus on a horizontal development and exploitation program supported by an extensive technical
database and the Earth Model that help us to define and optimize the horizontal targets.
As of December 31, 2014, our understanding of the stacked reservoir formations in our Permian-Garden City acreage
has been significantly enhanced through the development of the Earth Model. This leads us to believe that each of our four
primary 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 us and 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 the Earth
Model analysis, we believe we have confirmed that all three Wolfcamp zones share many petrophysical attributes and
production profiles. Through the utilization of our Earth Model, we have identified both vertical and horizontal petrophysical
changes across our acreage that we believe will enable us to develop the potential of each targeted interval in an efficient and
cost-effective manner.
As of December 31, 2014, we had successfully drilled and completed 127 Wolfcamp horizontal wells.
Upper Wolfcamp. As of December 31, 2014, we estimated that 90,000 net acres of our Permian-Garden City area
had been de-risked for horizontal Upper Wolfcamp development and have drilled and completed 75 horizontal wells.
Middle Wolfcamp. As of December 31, 2014, we estimated that 90,000 net acres of our Permian-Garden City area
had been de-risked for horizontal Middle Wolfcamp development and have drilled and completed 31 horizontal wells.
Lower Wolfcamp. As of December 31, 2014, we estimated that 83,000 net acres of our Permian-Garden City area
had been de-risked for horizontal Lower Wolfcamp development and have drilled and completed 21 horizontal wells.
The Cline shale resource play
As of December 31, 2014, we estimated that 137,000 net acres of our Permian-Garden City area had been de-risked
for horizontal Cline development. In 2014, we successfully drilled and completed ten horizontal wells and now have a total of
47 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
14
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
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.
We continue to evaluate the development opportunities in other formations including the Spraberry, Strawn, Canyon
and Atoka/Barnett/Woodford. Utilizing many of the components of our technical database, we drilled and completed our first
Canyon well in 2014. The Canyon zone is found at a depth of 8,250 to 9,000 feet and has a gross thickness ranging from 600 to
875 feet across a large portion of our Permian-Garden City acreaege. Our acreage is located structurally "down-dip" from the
legacy Canyon Gas Field to the east. We believe that with additional delineation drilling, we may be able to determine that the
Canyon zone will add a significant number of drilling locations across a majority of our acreage.
Other Properties
In addition to our Permian-Garden City acreage, we currently hold 44,949 net acres in other areas, including the
Dalhart Basin, located on the western side of the Texas Panhandle. We anticipate little or no activity on the other properties in
2015. Approximately 60% of this acreage will expire in 2015 absent drilling or renegotiation of the applicable leases.
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 247,322 MBOE on a two-stream basis as of December 31, 2014, of which
43% were classified as proved developed reserves, and 57% are attributable to oil reserves. The following table presents
summary data for each of our core operating areas as of December 31, 2014. Our estimated proved reserves as of December 31,
2014 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." Effective
January 1, 2015, we will report our production volumes on a three-stream basis, which separately reports natural gas liquids
from natural gas and crude oil.
Area:
Permian Basin ....................................................................................................................
Other Properties .................................................................................................................
Total.................................................................................................................................
(MBOE)
247,313
9
247,322
100%
—%
100%
As of December 31, 2014
Proved reserves
% of total
15
1,859
11,388
3,757
73,620
349,620
131,890
111,498
552,702
203,615
The following table sets forth more information regarding our estimated proved reserves as of December 31, 2014 and
2013. Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves as of December 31, 2014 and
2013. The reserve estimates as of December 31, 2014 and 2013 were prepared in accordance with the SEC's rules regarding oil
and natural gas reserve reporting applicable to the periods presented. The information does not give any effect to our
commodity hedges.
Proved developed producing:
Oil and condensate (MBbl).............................................................................................................
Natural gas (MMcf) ........................................................................................................................
Total proved developed producing (MBOE)..................................................................................
53,270
272,674
98,715
36,019
191,694
67,968
As of December 31,
2014
2013
Proved developed non-producing:
Oil and condensate (MBbl).............................................................................................................
Natural gas (MMcf) ........................................................................................................................
Total proved developed non-producing (MBOE)...........................................................................
3,705
18,819
6,842
Proved undeveloped:
Oil and condensate (MBbl).............................................................................................................
Natural gas (MMcf) ........................................................................................................................
Total proved undeveloped (MBOE) ...............................................................................................
83,215
351,301
141,765
Estimated proved reserves:
Oil and condensate (MBbl).............................................................................................................
Natural gas (MMcf) ........................................................................................................................
Total estimated proved reserves (MBOE) ......................................................................................
Percent developed...........................................................................................................................
140,190
642,794
247,322
43%
35%
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, 2014 and 2013 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.
16
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 39 years of practical
experience with 31 years of this experience being in the estimation and evaluation of reserves. He has a Bachelors of Science
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 131,890 MBOE as of December 31,
2013 to 141,765 MBOE as of December 31, 2014. We estimate that we incurred $109 million of costs to convert 5,865 MBOE
of proved undeveloped reserves from 22 locations into proved developed reserves in 2014. New proved undeveloped reserves
of 41,757 MBOE were added during the year, with 97% coming from new horizontal Upper, Middle and Lower Wolfcamp and
Cline locations. Negative revisions to proved undeveloped reserves of 26,017 MBOE were due to the combined effect of
removing 226 proved locations and the net effect of redetermining 345 undeveloped locations. The 226 locations that were
removed were comprised of 223 vertical Wolfberry and three 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, 2014 reserve report are $2.3 billion. Based on this report, the capital estimated to be spent in
2015, 2016, 2017, 2018 and 2019 to develop the proved undeveloped reserves is $154 million, $302 million, $435 million,
$657 million and $746 million, respectively. Based on our anticipated cash flows and capital expenditures, as well as the
availability of capital markets transactions, all of the proved undeveloped locations are expected to be drilled within a five-year
period. Reserve calculations at any end-of-year period are representative of the Company's development plans at that time.
Changes in circumstance, including commodity pricing, oilfield service costs and availability and other economic factors may
lead to changes in development plans.
Sales volume, revenues and price history
The following table sets forth information regarding sales volumes, revenues, average sales prices and average costs
per BOE sold for the years ended December 31, 2014, 2013 and 2012. For these periods our reserves and production are
reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our liquids-rich
natural gas is included in the wellhead natural gas price. For additional information on price calculations, see the information in
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
17
(unaudited)
Sales volumes:
Oil (MBbl)..........................................................................................................
Natural gas (MMcf)(1).........................................................................................
Oil equivalents (MBOE)(2)(3) ..............................................................................
Average daily sales volumes (BOE/D)(3)............................................................
Revenues (in thousands):
Oil.......................................................................................................................
Natural gas..........................................................................................................
Average sales prices without hedges:
Benchmark oil ($/Bbl)(4).....................................................................................
Oil, realized ($/Bbl)(5).........................................................................................
Benchmark natural gas ($/MMBtu)(4) ................................................................
Natural gas, realized ($/Mcf)(5) ..........................................................................
Average price, realized ($/BOE)(5) .....................................................................
Average sales prices with hedges(6):
Oil, hedged ($/Bbl).............................................................................................
Natural gas, hedged ($/Mcf)...............................................................................
Average price, hedged ($/BOE) .........................................................................
Average cost per BOE sold:
Lease operating expenses ...................................................................................
Production and ad valorem taxes .......................................................................
Midstream service expense ................................................................................
General and administrative(7)..............................................................................
Depletion, depreciation and amortization ..........................................................
_______________________________________________________________________________
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
For the years ended December 31,
2014
2013
2012
6,901
28,965
11,729
32,134
571,620
165,583
93.00
82.83
4.41
5.72
62.86
85.77
5.73
64.62
8.23
4.29
0.46
9.04
21.01
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
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
0.30
8.00
20.87
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
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
0.23
5.50
21.33
(1) Excludes natural gas produced and consumed in operations of 169 MMcf for the year ended December 31, 2014.
There were no comparable amounts for the years ended December 31, 2013 or 2012.
(2) Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(3) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in
the table above.
(4) 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.
(5) 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.
(6) 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.
(7) General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $23.1
million, $21.4 million and $10.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Excluding stock-based compensation, net of amount capitalized, from the above metric results in general and
administrative cost per BOE sold of $7.07, $6.09 and $4.61 for the years ended December 31, 2014, 2013 and 2012,
respectively.
18
Productive wells
The following table sets forth certain information regarding productive wells in each of our core areas as of December
31, 2014. 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 natural 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
Average WI %
Permian Basin:
Operated Permian-Garden City..............................
Non-Operated Permian Garden City......................
Other Properties.........................................................
Total......................................................................
950
140
1
1,091
179
10
—
189
1,129
150
1
1,280
1,080
43
1
1,124
96%
29%
95%
88%
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own
an interest as of December 31, 2014 for each of our core operating areas, including acreage held by production ("HBP" in the
table below). 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
112,465
102,869
478
465
112,943
103,334
640
502
113,583
103,836
73,762
52,237
125,999
54,091
180,090
52,536
40,813
93,349
44,447
137,796
186,227
52,715
238,942
54,731
293,673
155,405
41,278
196,683
44,949
241,632
%
HBP
66%
1%
1%
43%
Permian Basin:
Permian-Garden City.......
Permian-China Grove......
Permian Total...................
Other Properties ..................
Total..............................
Undeveloped acreage expirations
The following table sets forth the gross and net undeveloped acreage in our core operating areas as of December 31,
2014 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.
2015
2016
2017
2018
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Permian Basin:
Permian-Garden City..............
Permian-China Grove.............
Permian Total .........................
Other Properties .........................
Total.......................................
22,915
47,551
70,466
36,219
106,685
15,211
37,168
52,379
26,641
79,020
8,731
4,686
13,417
2,741
16,158
7,057
3,645
10,702
2,418
13,120
4,038
—
4,038
10,941
14,979
1,983
—
1,983
11,096
13,079
8,068
—
8,068
4,190
12,258
8,068
—
8,068
4,122
12,190
Of the total undeveloped acreage identified as expiring over the next three years, approximately 3,165 net acres have
PUD reserves on location. These PUD reserves represent approximately 3.7% of the Company's overall PUD reserves. The
Company anticipates using lease extensions and drilling to hold the leases associated with these 3,165 net acres. Less than 1%
of the net acres of leasehold that were identified as attributable to PUD reserves and potentially expiring in 2014 actually
expired. The remainder of such acreage was kept either through lease extensions or drilling.
19
Drilling activity
The following table summarizes our drilling activity for the years ended December 31, 2014, 2013 and 2012. 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
2014
2013
2012
Gross
Net
Gross
Net
Gross
Net
219
—
219
2
1
3
183.9
—
183.9
1.8
1.0
2.8
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
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 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; however, we believe that our customer diversification
affords us optionality in our sales destination. 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, 2014, we were committed to deliver for sale or transportation the following fixed quantities of
production under certain contractual arrangements that specify the delivery of a fixed and determinable quantity.
Crude Oil (MBbl)
Sales Commitments ................................................................
Transportation Commitments.................................................
Field ....................................................................................
To U.S. Gulf Coast..............................................................
Natural gas (MMcf)
Sales Commitments ................................................................
Transportation Commitments.................................................
Total (MBOE).....................................................................
Total
2015
2016
2017
2018 and
after
30,151
9,180
6,935
8,030
6,006
108,795
36,500
76,765
—
6,059
3,060
8,540
—
9,709
3,650
6,474
—
13,359
3,650
79,668
26,140
5,966
55,785
—
—
188,240
19,722
21,373
26,033
121,112
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. We
have firm field transportation agreements that enable us or the purchasers of our oil production to move oil from our production
area to the major market hubs of Midland, Texas and Colorado City, Texas. We also have a firm transportation agreement to
move oil from Colorado City, Texas to the U.S. Gulf Coast. We expect to fulfill these firm transportation commitments
primarily by utilizing the volumes under our firm sales commitments.
Our proved reserves have been equivalent or greater than our delivery commitments during the three most recent
years, and we expect such reserves will continue to exceed our future commitments. However, in certain instances, we have
used spot market purchases in order to meet commitments in certain locations or due to favorable pricing. We anticipate
continuing this practice in the future. Also, if our proved reserves are not sufficient to satisfy our delivery commitments, we can
and may use spot market purchases to fulfill the commitments.
In the current market environment, we believe that the loss of any one of our major purchasers would not have a
20
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 9 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 oil and 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, 2014, 43% of our leasehold acreage was held by production.
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 a wide range of companies in our
industry, including those that have greater resources than we do and those that are smaller with fewer ongoing obligations.
Many of the larger 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. Many of the smaller companies have a lower
cost structure and more available cash. These companies may be able to pay more for productive properties and exploratory
locations or 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 of the inherent advantages of some of our competitors,
those companies may have an advantage in bidding for exploratory and producing properties.
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 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
21
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. Based upon results of testing the performance of recycled flowback/produced water in our
fracing operations on a limited number of wells, we have constructed a water recycle facility on one of our production corridors
and anticipate expanding our recycling activities in the future.
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 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."
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
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
22
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
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
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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.
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. Also, the EPA is
updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by
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states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. In addition, in
May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and
issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used
in hydraulic fracturing. The public comment period ended on September 18, 2014. 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 March 2015. 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 early 2015. 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. Additionally, on October 28, 2014, the RRC
adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will
receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the
U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100
square miles around a proposed, new disposal well. The disposal well rule amendments also clarify the RRC's authority to
modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic
activity. The disposal well rule amendments became effective November 17, 2014. Also, in May 2013, the RRC adopted new
rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate
nearby water resources. The new rules took effect in January 2014. 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. The DOI announced its intent to finalize the rule
in 2014, however the final rule remains pending. 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 ("NSPS") and National Emission Standards for
Hazardous Air Pollutants ("NESHAP"). The rule includes NSPS standards for completions of hydraulically fractured gas wells
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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. 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. On December 19, 2014, the EPA released final updates and clarifications to the NSPS
standards. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-
forming VOC emissions from the oil and gas industry. 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 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. The tailoring rule established new GHG emissions thresholds that
determine when stationary sources must obtain permits under the Prevention of Significant Deterioration ("PSD") and Title V
programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA ("UARG v. EPA"), the Supreme Court
held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions.
The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at
sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing
initial guidance on GHG permitting requirements in response to the Court's decision in UARG v. EPA. In its preliminary
guidance, the EPA indicates it will undertake a rulemaking action no later than December 31, 2015 to rescind any PSD permits
issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted
"no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and
conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. 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
26
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. In December 2014, the EPA
published a proposed rule to amend the GHG Reporting Program to add reporting of GHG emissions from gathering and
boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas
transmission pipelines. The rule underwent an extended public comment period, which closed on February 24, 2015.
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.
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 2013 or 2014.
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
27
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.
The disclosure below relates solely to activities conducted by EIG and 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 had any involvement in or control over the disclosed activities of EIG
or 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 as to the accuracy or completeness of the disclosure nor do we
or Warburg Pincus undertake any obligation to correct or update it.
As to EIG:
Laredo understands that EIG's affiliates intend to disclose in their next annual or quarterly SEC report that:
"On July 2, 2013, the billing information for a subscriber account, or the Subscriber Account was updated to include
Seyed Mahmoud Mohaddes, or Mohaddes. On September 16, 2013, the Office of Foreign Assets Control, ("OFAC"),
designated Mohaddes as a Specially Designated National, or ("SDN"), pursuant to 31 C.F.R. Part 560.304. On or around
September 26, 2014, during a routine compliance scan of new and existing subscriber accounts, EIG discovered that Mohaddes
was named as an account contact for the Subscriber Account. EIG promptly suspended the Subscriber Account, locked the
domain name IOCUKLTD.COM, which was registered to the Subscriber Account, and reported the domain name to OFAC as
potentially the property of a SDN subject to blocking pursuant to Executive Order 13599. Since September 16, 2013, when
Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber Account for web
hosting and domain privacy services. EIG has ceased billing for the Subscriber Account. To date, EIG has not received any
correspondence from OFAC regarding this matter.
On July 10, 2014, OFAC designated each of Stars Group Holding, or Stars, and Teleserve Plus SAL, or Teleserve, as
SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global Terrorism Sanctions
Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG's compliance review processes, EIG discovered that the
domain names associated with each of Stars, STARSCOM.NET, and Teleserve, TELESERVEPLUS.COM, or collectively, the
Stars/Teleserve Domain Names, were registered through EIG's platform. EIG immediately took steps to suspend and lock the
Stars/Teleserve Domain Names to prevent them from being transferred or resolving to a website, and EIG promptly reported
the Domain Names as potentially blocked property to OFAC. EIG did not generate any revenue from the Stars/Teleserve
Domain Names between when they were added to the SDN list on July 10, 2014 and when EIG discovered that they were
registered through EIG's platform on July 15, 2014. To date, EIG has not received any correspondence from OFAC regarding
the matter.
On July 15, 2014 during a compliance scan of all domain names on one of our platforms, EIG identified the domain
name KAHANETZADAK.COM, or (the "Domain Name"), which was listed as an ‘also known as,' or AKA, of the entity
Kahane Chai which operates as the American Friends of the United Yeshiva. Kahane Chai was designated as a SDN on
November 2, 2001 pursuant to Executive Order 13224. Because the Domain Name was transferred into a customer account of
one of EIG's resellers, there was no direct financial transaction between EIG and the registered owner of the Domain Name.
The Domain Name was suspended upon EIG's discovering it on EIG's platform, and EIG reported the Domain Name to OFAC
as potentially the property of a SDN. To date, EIG have not received any correspondence from OFAC regarding the matter."
As to SAMIH:
Laredo understands that SAMIH's affiliates intend to disclose in their next annual or quarterly SEC report that:
"Santander UK holds frozen savings and current accounts for three customers resident in the U.K. who are currently
designated by the U.S. for terrorism. The accounts held by each customer were blocked after the customer's designation and
remained blocked and dormant throughout 2014. No revenue has been generated by Santander UK on these accounts. The bank
account held for one of these customers was closed in the fourth quarter of 2014.
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An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions
Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations ("NPWMD sanctions program"), holds a
mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be
permitted) under this mortgage although Santander UK continues to receive repayment installments. In 2014, total revenue in
connection with the mortgage was approximately £2,580 and net profits were negligible relative to the overall profits of
Santander UK. The same Iranian national also holds two investment accounts with Santander Asset Management UK Limited.
The accounts have remained frozen during 2014. The investment returns are being automatically reinvested, and no
disbursements have been made to the customer. Total revenue for the Santander Group in connection with the investment
accounts was £250 and net profits in 2014 were negligible relative to the overall profits of Banco Santander, S.A.
In addition, during the third quarter 2014, Santander UK identified two additional customers: a U.K. national
designated by the U.S. under the NPWMD sanctions program held a business account. No transactions were made and the
account was closed in the fourth quarter of 2014. No revenue or profit has been generated. A second U.K. national designated
by the U.S. for reasons of terrorism held a personal current account and a personal credit card account, both of which were
closed in the third quarter of 2014. Although transactions took place on the current account during the third quarter of 2014,
revenue and profits generated were negligible. No transactions took place on the credit card."
Employees
As of December 31, 2014, we had 420 full-time employees. We also employed a total of 71 contract personnel who
assist our full-time employees with respect to specific tasks and perform various field and other services. On January 20, 2015,
we announced the closing of our Dallas, Texas area office and the termination of approximately 75 employees Company-wide.
We also released 24 contract personnel. See Note 16.b to our audited consolidated financial statements included elsewhere in
this Annual Report. Our future success will depend partially on our ability to identify, attract, retain and motivate qualified
personnel. We are not a party to any collective 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 900, Tulsa, Oklahoma 74119, and the phone number at
this address is (918) 513-4570. We also lease corporate offices in Midland, Texas. On January 20, 2015, we announced that we
will be closing our Dallas, Texas area office. We are currently still leasing the office space but are actively exploring alternative
arrangements.
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 900, 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 continuing and 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 as well as negatively impact our stock price.
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, and this volatility has been evident in the last quarter of 2014 and has continued into the first quarter of 2015.
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,
natural gas and NGL;
the level of global oil, natural gas and NGL exploration and production;
the level of global oil, natural gas and NGL inventories, in particular due to supply growth from the United States;
the price and quantity of U.S. imports and exports of oil, natural gas, including liquefied natural gas, and NGL;
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, Ukraine and Russia;
actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil
and natural gas price and production controls;
the extent to which U.S. shale producers become "swing producers" adding or subtracting to the world supply
totals of oil, natural gas and NGL;
future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
current and future regulations regarding well spacing;
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;
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• 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, natural gas and NGL 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. A continuing decrease 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. Furthermore, under our Senior Secured Credit Facility, scheduled borrowing base
redeterminations occur each May 1 and November 1 and the lenders have the right to call for an interim redetermination of the
borrowing base one time between any two redetermination dates and in other specified circumstances. As a result, a substantial
or extended decline in oil and natural gas prices may materially and adversely impact our borrowing base in future borrowing
base redeterminations, which could trigger repayment obligation under the Senior Secured Credit Facility to the extent our
outstanding loans under the Senior Secured Credit Facility exceed the redetermined borrowing base, and otherwise materially
and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital
expenditures. In addition, lower oil and natural gas prices may cause a decline in our stock price.
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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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declines in oil and natural gas prices;
limited availability of financing or capital at acceptable rates or terms;
limitations in the market for oil and natural gas;
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; and
title problems.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory
initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial
condition, operating results and prospects.
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. In October 2014,
the RRC adopted new regulations effective as of November 17, 2014 that require additional supporting documentation,
including records from the U.S. Geological Survey regarding previous seismic events in the area, as part of applications for
new disposal wells. The new regulations also clarify the RRC's ability to modify, suspend or terminate a disposal well permit if
scientific data indicates it is likely to contribute to seismic activity. Because of the necessity to safely dispose of water produced
during drilling and production activities, these regulations, or others like them, could have a material adverse effect on our
future business, financial condition, operating results and prospects. See "Item 1. Business—Regulation of the oil and natural
gas industry" for a further description of the laws and regulations that affect us.
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, propants 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
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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. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the
Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release
draft criteria in early 2016. In addition, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking
public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure
of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014.
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 March 2015.
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
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 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. On December 19, 2014, the EPA
released final updates and clarifications to the NSPS standards. In addition, on January 14, 2015, EPA announced a series of
steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry. 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. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed,
among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic
fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended
to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The
disposal well rule amendments also clarify the RRC's authority to modify, suspend or terminate a disposal well permit if
scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments became
effective November 17, 2014. Also, in May 2013, the RRC adopted new rules governing well casing, cementing and other
standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules took
effect in January 2014. 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 their wells meet certain construction standards and (iii) establish site plans to
manage flowback water. The DOI announced its intent to finalize the rule in 2014, however, the final rule remains pending.
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
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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 early 2015.
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 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. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed,
among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic
fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended
to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The
disposal well rule amendments also clarify the RRC's authority to modify, suspend or terminate a disposal well permit if
scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments become
effective November 17, 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.
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.
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. In 2014, negative revisions of 26,017 MBOE were due to the combined effect of
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removing 226 proved locations and the net effect of redetermining 345 undeveloped locations. The 226 locations that were
removed were comprised of 223 vertical Wolfberry and three short horizontal laterals.
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 17.d in our audited consolidated financial statements included
elsewhere in this Annual Report.
Also, the substantial decrease in oil and natural gas prices that began in the second half of 2014 and has continued
into the first quarter of 2015, if continued or maintained, could have the effect of rendering uneconomic a portion (which could
be significant) of our exploration, development and exploitation projects. This would result in our having to make downward
adjustments (which could be significant) to our estimated proved reserves.
As a result of the recent commodity price 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. The
substantial decrease in oil and natural gas prices that began in the second half of 2014 and which has continued into the first
quarter of 2015, if continued or maintained, will have the effect of requiring us to 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 2.h
to our audited consolidated financial statements included elsewhere in this Annual Report for additional information.
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.
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. There is a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the
light sweet crude oil being produced in the U.S. If the export limitations noted above continue and light sweet crude oil
production continues to increase, demand for our light crude oil production could result in widening price discounts to the
world crude prices and potential shut-in of production due to a lack of sufficient markets.
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
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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
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.
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, or if legislation is enacted that negatively impacts the current regulatory process under which allocation wells are
currently permitted, 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.
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.
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.
Unless we replace our oil and natural gas production, 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
affected.
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Currently, we receive incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future
hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be
adversely impacted.
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 operations gain (loss) on derivatives. Loss (gain) 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, 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."
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;
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.
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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 on a variety of factors, including the availability,
proximity, capacity and quality constraints of transportation and storage 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 products and our access
to them may be limited or denied. Our failure to obtain such services on acceptable terms could materially harm our business.
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. The crude oil pipelines that transport our crude oil to market have quality specifications, including a Reid
Vapor Pressure ("RVP") specification. While our tank batteries and equipment are designed to deliver crude oil that meets all
pipeline specifications, including RVP, there is a risk that our crude oil production at any of our tank batteries could have an
RVP that exceeds the pipeline specifications. The pipelines have the right under their tariffs to request that crude oil that does
not meet their quality specifications, including RVP, be shut in until such crude is brought within quality specifications. If, in
the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or
specifications 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, could
materially and adversely affect our financial condition and results of operations.
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" and other risk factors described in this "Item
1A. Risk Factors" for a further description of the laws and regulations that affect us.
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",
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
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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.
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. The tailoring rule established new GHG emissions
thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration
("PSD") and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA ("UARG v.
EPA"), the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason
of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology
for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two
memoranda providing initial guidance on GHG permitting requirements in response to the Court's decision in UARG v. EPA. In
its preliminary guidance, the EPA indicates it will undertake a rulemaking action no later than December 31, 2015 to rescind
any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a
narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the
terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit.
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. In December 2014, the EPA
published a proposed rule to amend the GHG Reporting Program to add reporting of greenhouse gas emissions from gathering
and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas
transmission pipelines. The rule is underwent an extended public comment period which closed on February 24, 2015.
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.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with
our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal
oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity
Futures Trading Commission (the "CFTC") adopt rules or regulations implementing the Dodd-Frank Act and providing definitions
of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution
practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives
activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC has issued many
rules to implement the Dodd-Frank Act, including a rule, which we refer to as the "Mandatory Clearing Rule," requiring clearing
of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently
have), establishing an "end-user" exception to the Mandatory Clearing Rule, which we refer to as the "End-User Exception," and
a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further
proceedings, imposing position limits. The CFTC proposed a new version of this rule, which we refer to as the "Re-Proposed
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Position Limit Rule," with respect to which the comment period has closed but a final rule has not been issued. In addition, the
CFTC and bank regulators re-proposed rules, which we refer to as the "Re-Proposed SD/MSP Margin Rules," which, if adopted,
would require that swap dealers and major swap participants receive initial and variation margin on uncleared swaps with financial
end-users with material swaps exposures, swap dealers and major swap participants.
We qualify for and will utilize the End-User Exception to the Mandatory Clearing Rule if it is expanded to cover swaps
in which we participate, our hedging and other activities are such that we will not be required to post margin under the Re-Proposed
SD/MSP Margin Rules, if adopted, and the quantities under the swaps in which we participate are well within applicable limits
under the Re-Proposed Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if
not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties
who do not qualify for the End-User Exception and, if the Re-Proposed SD/MSP Margin Rules are adopted, will be subject to
such rule and required to post margin in accordance with such rule in connection with their swaps with other swap dealers and
major swap participants. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-
Proposed Position Limit Rule and the Re-Proposed SD/MSP Margin Rules are ultimately effected, such proposed rules could
significantly increase the cost of our derivative contracts (including through our being required to post collateral), materially alter
the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against
risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts, and increase
our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and
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. Finally, 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. Any of these consequences could have a material adverse effect on us, our financial condition, and
our results of operations.
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 25, 2015 we have $900.0 million of elected commitment 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 $900.0 million elected commitment on our Senior Secured Credit Facility would result in increased
annual interest expense of $9.0 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.
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, 2014, 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.
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
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risk is through net joint operations receivables ($33.8 million as of December 31, 2014) and the sale of our oil and natural gas
production ($57.1 million in receivables as of December 31, 2014), 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 36.0%
of our total oil and natural gas revenues for the year ended December 31, 2014. See Note 9 to our audited consolidated
financial statements included elsewhere in this Annual Report. 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. Current economic circumstances may further increase these risks.
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 and other data, including our Earth Model, 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 other data, such as that incorporated into our
Earth Model that provide either visualization techniques and/or statistical analyses 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.
The Earth Model is reliant upon data that is subject to interpretation and is itself the product of interpretation.
Therefore, there is no guarantee that the data it produces or our interpretation of that data will be correct. The Earth Model is a
new process and there is no guarantee that the initial rates of correlation will be duplicated.
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.
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. From time to time, 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, in recent years the high level of drilling activity in the Permian Basin has resulted in
equipment shortages in those areas. We have committed, and we may in the future commit, to drilling contracts with various
third parties that contain penalties for early terminations. These penalties could negatively impact our financial statements upon
contract termination. As a result of our reduced 2015 capital expenditure budget compared to 2014, we have begun releasing
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drilling rigs as their contracts came close to expiration and incurred related expenses of $0.5 million. Rig 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.
Competition in the oil and natural gas industry is intense, making it 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 may 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. 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. Especially in
times when commodity prices are high, the demand for drilling rigs that are able to drill horizontally in the Permian Basin
increases. 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. 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 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 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, 2014, Warburg Pincus owned 40.3% 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 change its ownership position in our
stock. 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 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.
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
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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.
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:
•
•
•
•
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 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."
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 25, 2015, we had total long-term indebtedness of $1.9 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.
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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:
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•
incur additional indebtedness;
pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted
payments;
• make certain investments;
•
•
•
•
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.
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 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.
If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to
the ownership change to offset future taxable income.
As of December 31, 2014, we had a net operating loss ("NOL") carryforward for federal income tax purposes of
approximately $1.0 billion. If we were to experience an "ownership change," as determined under Section 382 of the Internal
Revenue Code, our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership
change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of
our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to
the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an
ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or
more "5% shareholders" (as defined in the Internal Revenue Code) at any time during a rolling three-year period.
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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.
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
The concentration of our capital stock ownership among our largest stockholder will limit your ability to influence
corporate matters.
As of December 31, 2014, Warburg Pincus owned 40.3% 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
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.
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
44
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:
•
•
•
•
•
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 availability of shares for sale in the future could reduce the market price of our common stock.
Our board of directors has the authority, without action or vote of our stockholders, to issue all or any part of our
authorized but unissued shares of common stock. In the future, we may issue securities to raise cash for acquisitions, to pay
down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to
satisfy our obligations under our incentive plans. 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, 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.
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.
45
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.
46
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:
2014:
Fourth Quarter ...............................................................................................................................
Third Quarter .................................................................................................................................
Second Quarter ..............................................................................................................................
First Quarter...................................................................................................................................
2013:
Fourth Quarter ...............................................................................................................................
Third Quarter .................................................................................................................................
Second Quarter ..............................................................................................................................
First Quarter...................................................................................................................................
Price per share
High
Low
$
$
$
$
$
$
$
$
22.82
30.80
30.98
28.08
33.52
30.00
20.85
20.03
$
$
$
$
$
$
$
$
7.39
21.36
25.43
22.91
25.30
20.21
15.95
16.56
On February 25, 2015, the last sale price of our common stock, as reported on the NYSE, was $13.04 per share.
Holders. As of February 23, 2015, 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, 2014 - October 31, 2014 ................
November 1, 2014 - November 30, 2014 ........
December 1, 2014 - December 31, 2014 .........
______________________________________________________________________________
Total number of
shares withheld(1)
4,922
1,867
3,944
$
$
$
Average price
per share
20.26
16.55
9.27
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.
47
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, 2014, 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.
48
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 or 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, 2014, 2013 and 2012 and the balance sheet data as of December 31, 2014 and 2013 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, 2011 and 2010 and the balance sheet data as of December 31, 2012,
2011 and 2010 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
Income from continuing operations before income taxes
Income tax (expense) benefit
Income from continuing operations
For the years ended December 31,
2014
2013(1)
2012
2011
2010
$ 793,885
$ 665,257
$ 583,894
$ 506,347
$ 239,791
567,499
226,386
203,473
429,859
(164,286)
265,573
450,906
411,954
303,827
164,230
214,351
(23,267)
191,084
(74,507)
116,577
171,940
(77,176)
94,764
(33,003)
61,761
(107)
$ 61,654
202,520
(36,932)
165,588
(59,612)
105,976
(422)
$ 105,554
75,561
(12,516)
63,045
24,847
87,892
(1,644)
$ 86,248
Income (loss) from discontinued operations, net of tax
—
1,423
Net income ........................................................................
$ 265,573
$ 118,000
Net income per common share:
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.........................................................
$
$
$
$
1.88
—
1.88
1.85
—
1.85
$
$
$
$
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 3.e 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.
49
(in thousands)
Balance sheet data:
2014
2013
2012
2011
2010
As of December 31,
Cash and cash equivalents .......................................
Net property and equipment.....................................
Total assets...............................................................
Current liabilities .....................................................
Long-term debt.........................................................
Stockholders' equity.................................................
$
29,321
$
198,153
$
33,224
$
28,002
$
31,235
3,354,082
2,204,324
2,113,891
1,378,509
809,893
3,932,549
2,623,760
2,338,304
1,627,652
1,068,160
425,025
253,969
262,068
1,801,295
1,051,538
1,216,760
1,563,201
1,272,256
831,723
214,361
636,961
760,013
150,243
491,600
411,099
(in thousands)
Other financial data:
For the years ended December 31,
2014
2013(1)
2012
2011
2010
Net cash provided by operating activities................
Net cash used in investing activities
........................
Net cash provided by financing activities................
$
498,277
(1,406,961)
739,852
$
$
364,729
(329,884)
130,084
$
376,776
(940,751)
569,197
344,076
(706,787)
359,478
$
157,043
(460,547)
319,752
_______________________________________________________________________________
(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 3.e 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)...................................................
_______________________________________________________________________________
597,769
2014
2013
$
$
472,166
2012
2011
2010
$
443,434
$
384,342
$
188,568
(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of
Adjusted EBITDA to net income 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 debt issuance 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 commodity 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
50
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)
Net income ...........................................................................
Plus:
Interest expense..................................................................
Depletion, depreciation and amortization ..........................
Impairment of long-lived assets.........................................
Write-off of debt issuance 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 commodity derivatives, net.....................
Premiums paid for derivatives that matured during the
period(1) ..............................................................................
Non-cash stock-based compensation, net of amount
capitalized ..........................................................................
Deferred income tax expense (benefit) ..............................
Adjusted EBITDA ...........................................................
For the years ended December 31,
2014
2013
2012
2011
2010
$ 265,573
$ 118,000
$
61,654
$ 105,554
$
86,248
121,173
246,474
3,904
124
342
100,327
234,571
85,572
243,649
50,580
176,366
18,482
97,411
—
1,502
653
—
—
—
243
6,195
—
—
—
—
3,252
(327,920)
1,508
(79,878)
52
(8,388)
40
(19,736)
30
(5,815)
28,241
4,046
27,025
3,719
22,701
76,660
6,008
—
—
—
(7,419)
(11,292)
(9,135)
(4,104)
(5,934)
23,079
164,286
21,433
75,288
10,056
32,949
6,111
59,374
$ 597,769
$ 472,166
$ 443,434
$ 384,342
1,257
(25,812)
$ 188,568
______________________________________________________________________________
(1) Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective
periods presented.
51
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 audited 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 that 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, joint ventures and dispositions, 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." All amounts, dollars and percentages presented in this Annual Report are rounded and therefore
approximate.
Executive overview
We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas
properties primarily in the Permian Basin in West Texas. Since our inception, we have grown primarily through our drilling
program coupled with select strategic acquisitions and joint ventures. In December 2013, we completed the Internal
Consolidation, which simplified our corporate structure.
Our financial and operating performance for the year ended December 31, 2014 included the following:
•
•
Permian oil and natural gas sales of $737.2 million, compared to $605.2 million for the year ended December 31,
2013;
Permian average daily sales volumes of 32,134 BOE/D, compared to 24,960 BOE/D for the year ended
December 31, 2013;
• Estimated proved reserves of 247,322 MBOE, compared to 203,615 MBOE as of December 31, 2013; and
• Adjusted EBITDA (a non-GAAP financial measure) of $597.8 million, compared to $472.2 million for the year
ended December 31, 2013.
Recent developments
Recent drop in oil prices
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. The substantial decrease in oil and natural gas prices that began in the second half of 2014 and has continued
into the first quarter of 2015, if continued or maintained, may require us to incur non-cash full cost impairments in the future,
which could have a material adverse effect on our results of operations for the periods in which the impairments are incurred.
Potential transaction
As announced previously, we have been in discussions with interested parties regarding a potential joint development
opportunity involving, initially, a portion of our northern Permian-Garden City properties, and subsequently expanded to
include a portion of our other properties. These discussions are continuing and have centered on terms associated with funding
drilling opportunities. There is no assurance as to the form of a potential transaction or that a transaction will be consummated.
Restructuring
Following the recent drop in oil and natural gas prices, in an effort to reduce costs and better position ourselves for
ongoing efficient growth, on January 20, 2015, we committed to a company-wide restructuring and reduction in force (the
"RIF") that includes (i) the relocation of certain employees in our Dallas, Texas area office to our other existing offices in Tulsa,
Oklahoma and Midland, Texas; (ii) closing our Dallas, Texas area office; (iii) a workforce reduction of approximately 75
employees and (iv) the release of 24 contract personnel. The reduction in workforce was communicated to employees on
January 20, 2015 and was generally effective immediately. The relocation of our employees and the closing of our Dallas, Texas
area office are expected to be completed by June 1, 2015. Our compensation committee approved the RIF and the severance
package offered in connection with the RIF. We estimate the first-quarter 2015 financial statement impact to range between $6.0
- $7.0 million.
52
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 upside potential in the assets.
On July 12, 2012, we completed the acquisition of additional working interests in certain oil and natural gas properties
located in Glasscock County, Texas in the Permian Basin, 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 evaluated and unevaluated oil and natural gas properties
located in Glasscock County, Texas in the Permian Basin, from private parties for $36.7 million consisting of cash and 123,803
shares of our restricted common stock, subject to customary closing adjustments.
On February 25, 2014, we completed the acquisition of the mineral interests underlying 278 net acres in Glasscock
County, Texas in the Permian Basin for $7.3 million. These mineral interests entitle us to receive royalties on all production
from this acreage with no additional future capital or operating expenses required.
On June 11, 2014, we completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling
460 net acres, located in Reagan County, Texas in the Permian Basin for $4.7 million, net of closing adjustments. On June 23,
2014, we completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 24 net acres, located in
Glasscock County, Texas for $1.8 million.
On August 26, 2014, we completed a material acquisition of leasehold interests totaling 8,156 net acres in the Midland
Basin, primarily within our core development area, for $192.5 million.
Divestitures
On August 1, 2013, we completed the Anadarko Basin Sale, consisting of oil and natural gas properties located in the
Anadarko Granite Wash, Eastern Anadarko and Central Texas Panhandle (the "Anadarko Basin") in the State of Oklahoma and
the State of Texas, associated pipeline assets and various other related property and equipment 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 related
property and equipment have been presented as results of discontinued operations, net of tax. Accordingly, we have reclassified
certain prior period amounts in the audited consolidated financial statements included elsewhere in this Annual Report as
discontinued operations. See Notes 2.c and 3.e to our audited 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.
53
Common stock transactions
During the year ended December 31, 2014, Warburg Pincus distributed our common stock pro rata to certain of the
Warburg Pincus limited partners. As of February 23, 2015, Warburg Pincus owned 40.4% of our outstanding common stock.
The following details the distributions throughout the year ended December 31, 2014:
Date of distribution
March 4, 2014.............................................................................
May 12, 2014 ..............................................................................
Number of shares
distributed
Distribution % of Warburg Pincus'
holdings of our common stock prior to the
distribution
7,035,017
5,097,388
10%
8%
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, 2014, we had assembled
196,683 net acres in the Permian Basin, of which 155,405 net acres are located in our Permian-Garden City area.
Reserves and pricing
Our results of operations are heavily influenced by commodity prices, which have significantly declined in recent
months. 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. Oil
prices began to decline in June 2014 and in late November 2014 a rapid decline in oil prices occurred. 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 and ability to fund drilling projects, as well as the economic valuation
and economic recovery of oil and natural gas reserves.
Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves, reported on a two-stream
basis, as of December 31, 2014, 2013 and 2012. As of December 31, 2014, we had 247,322 MBOE of estimated proved
reserves as compared to 203,615 MBOE of estimated proved reserves as of December 31, 2013 and 188,632 MBOE of
estimated proved reserves as of December 31, 2012.
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 $91.48 per Bbl for oil and $4.25 per MMBtu for natural gas as of December
31, 2014, $93.52 per Bbl for oil and $3.57 per MMBtu for natural gas as of December 31, 2013 and $91.21 per Bbl for oil and
$2.63 per MMBtu for natural gas as of December 31, 2012. The prices used to estimate proved reserves for all periods do not
include 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 enabled us to offset a portion of the changes in
our cash flow 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 primarily derived from the sale of oil and natural gas and the sale of purchased oil within the
continental United States and do not include the effects of derivatives. For the year ended December 31, 2014, our revenues are
comprised of sales of 72% oil, 21% liquids-rich natural gas and 7% purchased oil. Our revenues may vary significantly from
period to period as a result of changes in volumes of production sold and/or changes in commodity prices.
Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to 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.
54
Midstream service expenses. These are costs incurred to operate and maintain our (i) oil and natural gas gathering
and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, rig fuel and centralized
compression infrastructure and (iv) water storage, recycling and transportation facilities.
Costs of purchased oil. These are costs associated with purchasing oil from other producers and the transportation
costs to bring it to market.
Drilling rig fees. These are early termination costs incurred for the termination of drilling rigs once drilling has
ceased at a well site.
General and administrative ("G&A"). 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, legal compliance and compensation expense related to employee and
director stock awards, performance awards 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 that represents changes in our asset
retirement liability due to the passage of time.
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 evaluated 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 unevaluated properties and major development projects for which evaluated reserves cannot yet be assigned,
less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing evaluated 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, or
in the case of leasehold improvements over the shorter of the estimated useful lives of the assets or the terms of the related
leases.
Impairment expense. Long-lived assets are considered impaired when their net carrying value is greater than the
future undiscounted cash flows. Once an asset is recognized as impaired, costs are incurred to write the asset down. With the
continuing volatility in commodity prices, we may incur write-downs on our oil and natural gas properties. Materials and
supplies and line-fill are recorded at the lower of cost or market ("LCM"), with costs determined using the weighted-average
cost method.
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 audited
consolidated statements of cash flows.
Gain (loss) on interest rate derivatives. In prior periods, 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 audited 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. We had no interest rate derivatives in place in
2014.
Income (loss) 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
income (loss) reflected in the audited consolidated statements of operations as "Loss from equity method investee" and the
carrying amount reflected in the audited consolidated balance sheet as "Investment in equity method investee." See Note 14 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 and our Senior Unsecured Notes. As a result, we incur interest
55
expense that is affected by both fluctuations in interest rates and our financing decisions. In prior periods, we 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 debt issuance 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.
Write-off of deferred loan costs. Debt issuance 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. Write-offs of such costs can
occur when borrowing terms change and/or debt has been extinguished.
Loss on disposal of assets, net. This represents losses recorded from selling or disposing of property and equipment.
Sale proceeds are compared with the recorded net book value of the asset and the appropriate gain (loss) is recorded.
Income tax expense. Income taxes in our financial statements are generally presented on a consolidated basis. 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 our oil and natural gas reserves (including
the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2014, 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.
56
Results of operations
For the year ended December 31, 2014 as compared to the year ended December 31, 2013, and for the year ended December
31, 2013 as compared to the year ended December 31, 2012
Sales volume, revenue and pricing
The following table sets forth information regarding oil and natural gas sales volumes, revenues and average sales
prices from continuing operations per BOE sold, for the periods presented:
(unaudited)
Sales volumes:
Oil (MBbl) .......................................................................................................
Natural gas (MMcf)(1) ......................................................................................
Oil equivalents (MBOE)(2)(3)............................................................................
Average daily sales volumes (BOE/D)(3)..........................................................
% Oil ................................................................................................................
Revenues (in thousands):
Oil ....................................................................................................................
Natural gas .......................................................................................................
Total revenues...........................................................................................
Average sales prices:
Oil, realized ($/Bbl)(4) ......................................................................................
Natural gas, realized ($/Mcf)(4) ........................................................................
Average price, realized ($/BOE)(4) ...................................................................
Oil, hedged ($/Bbl)(5) .......................................................................................
Natural gas, hedged ($/Mcf)(5) .........................................................................
Average price, hedged ($/BOE)(5) ....................................................................
_______________________________________________________________________________
For the years ended December 31,
2014
2013
2012
6,901
28,965
11,729
32,134
5,487
34,348
11,211
30,716
4,775
39,148
11,300
30,874
59%
49%
42%
$
$
$
571,620
165,583
737,203
82.83
5.72
62.86
85.77
5.73
64.62
$
$
$
494,676
170,168
664,844
90.16
4.95
59.29
88.68
4.98
58.66
$
$
$
414,932
168,637
583,569
86.89
4.31
51.65
85.59
4.92
53.22
(1) Excludes natural gas produced and consumed in operations of 169 MMcf for the year ended December 31, 2014.
There were no comparable amounts for the years ended December 31, 2013 or 2012.
(2) Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(3) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the
table above.
(4) 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.
(5) 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.
57
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,
2014
2013
2012
26,803
1,438
28,241
$
$
(149) $
4,195
4,046
$
(944)
27,969
27,025
(6,497) $
(922)
(7,419) $
(7,970) $
(3,322)
(11,292) $
(5,278)
(3,857)
(9,135)
The changes in prices and volumes shown in the oil and natural gas sales volumes, revenue and pricing table above
caused the following changes to our oil and natural gas revenue between the years ended December 31, 2012, 2013 and 2014:
(in thousands)
2012 Revenue.............................................................................................................
Effect of changes in price ......................................................................................
Effect of changes in volumes.................................................................................
Other ......................................................................................................................
2013 Revenue.............................................................................................................
Effect of changes in price ......................................................................................
Effect of changes in volumes.................................................................................
Other ......................................................................................................................
2014 Revenue.............................................................................................................
Oil
Natural gas
Total net
dollar effect
of change
$
414,932
$
168,637 $
583,569
17,942
61,812
(10)
494,676
(50,587)
127,544
(13)
571,620
$
21,982
(20,688)
237
170,168
22,303
(26,645)
(243)
165,583
$
39,924
41,124
227
664,844
(28,284)
100,899
(256)
737,203
$
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 $72.4 million, or 11%, for
the year ended December 31, 2014 as compared to the year ended December 31, 2013 is largely related to a 26% rise in the
production volume of oil due to an increased number of rigs in place during the year, along with a 16% increase in natural gas
prices realized, which were partially offset by a 16% decrease in natural gas production volumes attributable to the divestiture
of our Anadarko Basin assets. 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 following table sets forth information regarding midstream and sales of purchased oil revenues for the periods
presented:
(unaudited)
For the years ended December 31,
2014
2013
2012
Revenues (in thousands):
Midstream service revenue .............................................................................. $
Sales of purchased oil ......................................................................................
Total revenues........................................................................................... $
2,245 $
54,437
56,682 $
413 $
—
413 $
325
—
325
Midstream service revenue. Our midstream service revenue from operations increased by $1.8 million during the
year ended December 31, 2014 as compared to the year ended December 31, 2013 and $0.1 million during the year ended
December 31, 2013 as compared to the year ended December 31, 2012. These increases were due to the sale of natural gas,
58
natural gas liquids and condensate off our pipelines and facilities during each respective period as well as an increase in third-
party volumes transported through our oil and natural gas gathering and transportation systems and related facilities.
Sales of purchased oil. Our revenues from sales of purchased oil for the year ended ended December 31, 2014 were
$54.4 million. During the year ended December 31, 2014, we began purchasing oil from a producer in West Texas, transporting
the product on the Bridgetex Pipeline and selling the product to a third party in the Houston market.
Costs and expenses
The following table sets forth information regarding costs and expenses from continuing operations and average costs
per BOE sold for the periods presented:
(in thousands except for per BOE sold data)
Costs and expenses:
Lease operating expenses ..................................................................................
Production and ad valorem taxes.......................................................................
Midstream service expense................................................................................
Natural gas volume commitment - affiliates .....................................................
Costs of purchased oil .......................................................................................
Drilling rig fees..................................................................................................
General and administrative(1).............................................................................
Accretion of asset retirement obligations ..........................................................
Depletion, depreciation and amortization..........................................................
Impairment expense...........................................................................................
Total costs and expenses .................................................................................
Average costs per BOE sold:
Lease operating expenses ..................................................................................
Production and ad valorem taxes.......................................................................
Midstream service expense................................................................................
General and administrative(1).............................................................................
Depletion, depreciation and amortization..........................................................
Total.................................................................................................................
_________________________________________________________________________
For the years ended December 31,
2013
2014
2012
$
96,503
$
79,136
$
50,312
5,429
2,552
53,967
527
106,044
1,787
246,474
3,904
42,396
3,368
891
—
—
89,696
1,475
233,944
—
67,325
37,637
2,614
—
—
—
62,106
1,200
241,072
—
567,499
$
450,906
$
411,954
$
8.23
4.29
0.46
9.04
21.01
$
7.06
3.78
0.30
8.00
20.87
$
43.03 $
40.01 $
5.96
3.33
0.23
5.50
21.33
36.35
$
$
(1) General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $23.1 million,
$21.4 million and $10.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. Excluding
stock-based compensation, net of amount capitalized, from the above metric results in general and administrative cost
per BOE sold of $7.07, $6.09 and $4.61 for the years ended December 31, 2014, 2013 and 2012, respectively.
Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $17.4 million,
or 22%, compared to a 5% increase in production, for the year ended December 31, 2014 compared to 2013. On a per-BOE
sold basis, lease operating expenses increased in total to $8.23 per BOE sold as of December 31, 2014 from $7.06 per BOE
sold as of December 31, 2013. The increases were mainly due to (i) higher average lease operating expenses per-BOE sold on
our higher oil-weighted Permian production following the Anadarko Basin Sale, (ii) an increase in well count and (iii) higher
well service and workover 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 sold basis, lease operating
expenses increased in total to $7.06 per BOE sold as of December 31, 2013 from $5.96 per BOE sold as of December 31, 2012.
The increases were mainly due to (i) higher average lease operating expenses per-BOE sold 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.
59
Production and ad valorem taxes. Production and ad valorem taxes increased to $50.3 million for the year ended
December 31, 2014 from $42.4 million for the year ended December 31, 2013, an increase of $7.9 million, or 19%. Production
taxes are based on and increase in proportion to our oil and natural gas revenue. Ad valorem taxes decreased by $1.6 million for
the year ended December 31, 2014 compared to 2013, primarily as a result of the Anadarko Basin Sale. The ad valorem tax
decreases were partially offset by the ad valorem tax expense incurred for new wells drilled during the year ended
December 31, 2014.
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%. This was primarily the 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.
Midstream service expense. Midstream service expenses increased by $2.1 million, or 61%, for the year ended
December 31, 2014 compared to 2013, and $0.8 million, or 29%, for the year ended December 31, 2013 compared to 2012, due
to the expanded midstream service component of our business.
Costs of purchased oil. Costs of purchased oil for the year ended December 31, 2014 was $54.0 million. These costs
include purchasing oil from a producer and transporting the oil on the Bridgetex Pipeline to the Houston market. There were no
comparable amounts for the years ended December 31, 2013 and 2012.
General and administrative ("G&A").
The table below shows the changes in the significant components of general and administrative expense for the
periods presented:
(in thousands)
Changes in G&A:
Year ended December 31,
2014 compared to 2013
Year ended December 31,
2013 compared to 2012
Professional fees.......................................................................................
Salaries, benefits and bonuses ..................................................................
Charitable contributions ...........................................................................
Stock-based compensation, net of amount capitalized(1)..........................
Performance unit awards ..........................................................................
Production income....................................................................................
Other.........................................................................................................
Total change in G&A.............................................................................
$
$
____________________________________________________________________
6,851
$
6,249
3,106
1,646
(4,132)
(2,217)
4,845
16,348
$
(824)
17,493
80
11,377
2,936
(5,837)
2,365
27,590
(1) On January 1, 2014, we began capitalizing a portion of stock-based compensation for employees who are directly
involved in the acquisition and exploration of oil and natural gas properties into the full cost pool. Capitalized stock-
based compensation is included as an addition to "Oil and natural gas properties" in the audited consolidated balance
sheets included elsewhere in this Annual Report.
Year ended December 31, 2014 compared to 2013. G&A expense, excluding stock-based compensation, increased to
$83.0 million for the year ended December 31, 2014 from $68.3 million for the year ended December 31, 2013, an increase of
$14.7 million, or 22%. The increase is primarily due to the growth of our business, and accordingly our professional fees and
salaries and benefits have increased $13.1 million for the year ended December 31, 2014 compared to 2013. The increase
during the year ended December 31, 2014 was offset by the $6.4 million combined decrease in the fair value of our
performance unit awards and increase in production income and reduced employee bonuses. Professional fees increased mainly
due to fees paid to a consulting company engaged in 2014 to assist us with the optimization of our development operations. We
also pledged a $3.0 million charitable contribution during the year ended December 31, 2014, which will be paid in annual
payments through 2024. On a per-BOE sold basis, G&A expense, excluding stock-based compensation, increased to $7.07 per
BOE sold during the year ended December 31, 2014 from $6.09 per BOE sold during the year ended December 31, 2013. This
increase was a result of the growth in our overhead combined with our Permian production growth being partially offset by the
production associated with the divestiture of our Anadarko Basin assets.
Stock-based compensation increased to $27.7 million for the year ended December 31, 2014 from $21.4 million for
the year ended December 31, 2013, an increase of $6.3 million, mainly due to the issuance of 1,234,255 restricted stock awards
at a weighted-average grant price of $25.68 per share and 336,140 non-qualified restricted stock options to new and existing
60
employees and non-employee directors in the year ended December 31, 2014 compared to the issuance of 1,469,295 restricted
stock awards at a weighted-average grant price of $18.17 per share and 1,018,849 non-qualified restricted stock options to new
and existing employees and non-employee directors in 2013. Additionally, during the year ended December 31, 2014, we
issued 271,667 performance share awards to management and the associated expense amounted to $2.1 million for the year
ended December 31, 2014. No comparable awards were issued during 2013. This increase in stock-based compensation was
partially offset by management's decision to begin capitalizing a portion of stock-based compensation for employees who are
directly involved in the acquisition and exploration of our oil and natural gas properties into the full cost pool in 2014.
Capitalized stock-based compensation amounted to $4.7 million for the year ended December 31, 2014. No amounts were
capitalized during 2013.
The fair values of the restricted stock awards issued during 2014 and 2013 were calculated based on the value of our
stock price on the date of grant in accordance with GAAP and are being recognized on a straight-line basis over the requisite
service period of the awards. The fair values of our non-qualified restricted stock options were determined using a Black-
Scholes valuation model in accordance with GAAP and are being recognized on a straight-line basis over the four-year
requisite service period of the awards.
Our performance share awards are accounted for as equity awards. The fair value of the performance share awards
issued during 2014 was based on a projection of the performance of our stock price relative to our peer group utilized in a
forward-looking Monte Carlo simulation. The fair value of the performance share awards will not be re-measured after the
initial valuation of the awards and will be expensed on a straight-line basis over their three-year requisite service period.
Our 2013 and 2012 Performance Unit Awards, which settle in cash, are accounted for as liability awards. The
associated expense for these awards decreased by $4.1 million for the year ended December 31, 2014 compared to 2013 due to
(i) the quarterly re-measurement of the 2013 Performance Unit Awards based on the performance of our stock price relative to
the peer group utilized in the forward-looking Monte Carlo simulation and (ii) the final pay-out value of the 2012 Performance
Unit Awards due to the performance of our stock relative to the peer group during the corresponding performance period. The
fair value and corresponding liability related to the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million
and represents the cash payment made in the first quarter of 2015.
See Notes 2.r and 5 to our audited consolidated financial statements included elsewhere in this Annual Report for
additional information regarding our stock and performance based compensation.
Year ended December 31, 2013 compared to 2012. 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 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 lower total production growth due to the
divestiture of our Anadarko Basin assets.
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 issued to our employees and non-employee directors 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.
Performance unit award expense increased by $2.9 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 the peer groups 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.
These performance unit awards were paid in cash at $100.00 per unit totaling $2.1 million.
Depletion, depreciation and amortization ("DD&A"). DD&A was $246.5 million for the year ended December 31,
2014 as compared to $233.9 million for the year ended December 31, 2013 and $241.1 million for the year ended
December 31, 2012.
61
The following table provides components of our DD&A expense from continuing operations for the periods presented:
(in thousands except for per BOE sold data)
Depletion of evaluated oil and natural gas properties .........................................
Depreciation of midstream service assets............................................................
Depreciation and amortization of other fixed assets ...........................................
Total DD&A......................................................................................................
DD&A per BOE sold...........................................................................................
For the years ended December 31,
2014
2013
2012
$
237,067
$
227,992
$
237,130
4,303
5,104
1,510
4,442
797
3,145
$
$
246,474 $
233,944 $
241,072
21.01
$
20.87
$
21.33
DD&A increased by $12.5 million, or 5%, for the year ended December 31, 2014 as compared to 2013. The increase
is mainly due to (i) increased book value on new reserves added, (ii) higher total production levels, (iii) increased capitalized
costs for new wells completed in the year ended December 31, 2014, (iv) the impact of the Anadarko Basin Sale to the year
ended December 31, 2013 depletion and (v) the impact of $35.5 million in unevaluated properties' carrying costs being added
to the amortization base during the three months ended December 31, 2014, as management determined that we do not intend
to drill this non-core acreage.
The decrease in depletion of evaluated 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.
Impairment expense. Beginning in the fourth quarter of 2014, the Company owned oil line-fill in third-party
pipelines, which is accounted for at LCM. For the year ended December 31, 2014, the Company recorded a LCM adjustment of
$2.1 million related to its line-fill.
During the year ended December 31, 2014, the Company reduced materials and supplies by $1.8 million in order to
reflect the balance at LCM. The Company determined an LCM adjustment was not necessary for materials and supplies during
the years ended December 31, 2013 or 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):
Gain (loss) on derivatives:
For the years ended December 31,
2013
2014
2012
Commodity derivatives, net............................................................................
Interest rate derivatives, net............................................................................
Income (loss) from equity methods investee ....................................................
Interest expense.................................................................................................
Interest and other income ..................................................................................
Write-off of debt issuance costs........................................................................
Loss on disposal of assets, net ..........................................................................
Non-operating income (expense), net.............................................................
$
327,920
$
—
(192)
(121,173)
294
(124)
(3,252)
203,473
$
$
$
79,902
(24)
29
(100,327)
163
(1,502)
(1,508)
(23,267) $
8,800
(412)
—
(85,572)
59
—
(51)
(77,176)
62
Commodity derivatives. The table below shows the changes in the components of gain on commodity derivatives,
net for the periods presented:
(in thousands)
Changes in gain on commodity derivatives, net:
Year ended December 31,
2014 compared to 2013
Year ended December 31,
2013 compared to 2012
Fair value of commodity derivatives outstanding.....................................
Early terminations and modifications of commodity derivatives
received .....................................................................................................
Cash settlements received for matured commodity derivatives................
Total change in gain on commodity derivatives, net..............................
$
$
153,171
$
70,652
24,195
248,018
$
88,073
6,008
(22,979)
71,102
The year ended December 31, 2014 compared to 2013 increase in fair value of commodity derivatives outstanding is
the result of the changing relationship between our contract prices and the associated forward curves used to calculate the fair
value of our commodity derivatives in relation to expected market prices. In general, we experience gains during periods of
decreasing market prices and losses during periods of increasing market prices. The increase was partially offset by the cash
received for the early settlement in February 2014 of our oil basis swap differential between the Light Louisiana Sweet Argus
and the Brent International Petroleum Exchange index oil prices. The year ended December 31, 2013 compared to 2012
increase in fair value of commodity derivatives outstanding 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.
During the year ended December 31, 2014, we received $76.7 million in net proceeds from the early termination of
our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index
oil prices and the related physical contract. During the year ended December 31, 2013, 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. Net cash settlements
received for matured commodity derivatives are based on the cash settlement prices of our matured commodity derivatives
compared to the prices specified in the derivative contracts.
See Notes 2.f, 7 and 8 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.
Interest expense and interest rate swaps. Interest expense increased by $20.8 million, or 21%, for the year ended
December 31, 2014 compared to 2013, and $14.8 million, or 17%, for the year ended December 31, 2013 compared to 2012.
The increase is primarily due to the issuance of the January 2022 Notes in January 2014, which was partially offset by the
reduction in amount outstanding under our Senior Secured Credit Facility and the related commitment fees on the unused
portion of the banks' commitment on our Senior Secured Credit Facility.
The table below shows the changes in the significant components of interest expense for the periods presented:
(in thousands)
Changes in interest expense:
Year ended December 31,
2014 compared to 2013
Year ended December 31,
2013 compared to 2012
January 2022 Notes ...................................................................................
Senior Secured Credit Facility, net of capitalized interest(1) .....................
Change in net present value of deferred premiums paid for derivatives...
2019 Notes ................................................................................................
May 2022 Notes ........................................................................................
Other..........................................................................................................
Total change in interest expense.............................................................
$
$
_______________________________________________________________________
$
23,836
(2,587)
(242)
(162)
—
1
20,846
$
—
2,931
(206)
(20)
12,189
(139)
14,755
(1) Our Senior Secured Credit Facility was paid in full on August 1, 2013 and remained undrawn until September 3, 2014.
We had entered into certain variable-to-fixed interest rate derivatives that hedged 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
63
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.
Write-off of debt issuance costs. In January 2014, we wrote-off $0.1 million of debt issuance costs as a result of
changes in the borrowing base under our Senior Secured Credit Facility due to the issuance of the January 2022 Notes. In
August 2013, we wrote-off $1.5 million in debt issuance costs as a result of changes in the borrowing base under our Senior
Secured Credit Facility due to the Anadarko Basin Sale.
Disposal of assets. Loss on disposal of assets, net increased by $1.7 million for the year ended December 31, 2014
compared to 2013 and $1.5 million for the year ended December 31, 2013 compared to 2012. The 2014 increase over the prior
year is a result of losses related to sales of materials and supplies, vehicles and a write-off of abandoned internally developed
software during 2014, compared to a net gain recorded in 2013 mainly related to the sale of pipeline assets and various other
property and equipment associated with the Anadarko Basin Sale. 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 materials and supplies.
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.
Income tax expense. The fluctuations in income from continuing operations before income taxes is shown in the
table below:
(in thousands)
Income from continuing operations before income taxes ...................................
Income tax expense .............................................................................................
Income from continuing operations ..................................................................
Effective tax rate..................................................................................................
For the years ended December 31,
2013
2014
2012
$
$
429,859
(164,286)
265,573
$
$
191,084
(74,507)
116,577
$
$
94,764
(33,003)
61,761
38%
39%
35%
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, 2014 and December 31, 2013, certain
restricted stock awards vested at times when our stock price was lower than the fair value of those restricted stock awards 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, 2014 and 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.
We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-
employees are grouped into a single pool. As a result of these differences in book compensation cost and related tax deduction,
the tax impact of these shortfalls decreased by $0.3 million for the year ended December 31, 2014 compared to 2013 and
increased by $0.6 million for the year ended December 31, 2013 compared to 2012. There was no tax impact of shortfalls in the
year ended December 31, 2012 as all shares vested had a tax basis of zero and no stock options were exercised. For further
discussion see Notes 5.a, 5.b and 6 to our audited consolidated financial statements included elsewhere in this Annual Report.
As of December 31, 2014 and 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no
excess tax benefits had been recognized, and therefore the tax impact of these shortfalls is included in income tax expense
attributable to continuing operations for these respective periods. We expect income tax provisions for future reporting periods
will be impacted by these stock compensation tax deduction shortfalls; however, we cannot predict the stock compensation
shortfall impact because of dependency upon the future market price of our stock.
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,
2014
2013
2012
— $
1,423
$
(107)
Effective on the August 1, 2013 completion of the Anadarko Basin Sale, the operations and cash flows of these
properties were eliminated from our ongoing operations and we do not have continuing involvement in the operations of these
properties. Income (loss) from discontinued operations, net of tax, increased by $1.5 million for the year ended December 31,
64
2013 compared to 2012. The increases are a result of increased production over time that has attributed to growth in the
transportation and gathering income component of our midstream service revenue.
Liquidity and capital resources
Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from
our Senior Unsecured Notes offerings, borrowings under our Senior Secured Credit Facility and proceeds from the Anadarko
Basin Sale. We believe cash flows from operations and availability under our Senior Secured Credit Facility provide sufficient
liquidity to manage our cash needs, manage our contractual obligations and fund expected capital expenditures. A significant
portion of our capital expenditures can be adjusted and managed by us.
As we pursue reserves and production growth in the Permian Basin, we continually consider which financing
alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future financial
obligations, planned or accelerated capital expenditures and liquidity requirements. Our primary uses of capital have been for
the acquisition, exploration and development of oil and natural gas properties, Laredo Midstream's infrastructure development
and investments in Medallion, our equity method investee. 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 if we believe conditions to be favorable.
We continually seek to maintain a financial profile that provides operational flexibility. However, the recent decrease
in oil and natural gas prices may have a negative impact on our ability to raise additional capital and/or maintain our desired
levels of liquidity. At December 31, 2014, we had $600 million available for borrowings under our Senior Secured Credit
Facility and total debt of $1.8 billion, of which $300 million was outstanding under our Senior Secured Credit Facility. Our
total debt, less available cash on the balance sheet, was 3.0 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, 2014. We believe that our operating cash flow and the aforementioned liquidity sources combined with our decreased
capital budget for 2015 provide us with the financial resources to implement our planned exploration and development
activities. We use derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. More than 95% of our
expected oil production in 2015 is hedged at a weighted-average floor price of $80.99 per Bbl and 63% of our natural gas and
natural gas liquids production in 2015 is hedged at a weighted-average floor price of $3.00 per MMBtu. 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.
As of December 31, 2014, we had $300.0 million outstanding under our Senior Secured Credit Facility and $1.5
billion in Senior Unsecured Notes. We had $600.0 million available for borrowings under our Senior Secured Credit Facility
and $29.3 million in cash on hand for total available liquidity of $629.3 million as of December 31, 2014.
Subsequent to December 31, 2014, we borrowed an additional $135.0 million on our Senior Secured Credit Facility.
As of February 24, 2015, we had $1.9 billion in debt outstanding, $465.0 million available for borrowings under our Senior
Secured Credit Facility and $7.1 million in cash on hand for total available liquidity of $472.1 million.
Our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations in the
event of further 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)
Net cash provided by operating activities ...........................................................
Net cash used in investing activities....................................................................
Net cash provided by financing activities ...........................................................
Net (decrease) increase in cash and cash equivalents .......................................
2014
$
$
$
498,277
(1,406,961)
739,852
(168,832) $
$
2013
364,729
(329,884)
130,084
2012
376,776
(940,751)
569,197
164,929
$
5,222
For the years ended December 31,
For the years ended December 31, 2013 and 2012, the results of operations of the pipeline assets and various other
related 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 cash flows of discontinued operations separately from cash flows of 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.
65
Cash flows provided by operating activities
Net cash provided by operating activities was $498.3 million, $364.7 million and $376.8 million for the years ended
December 31, 2014, 2013 and 2012, respectively. The increase of $133.5 million from 2013 to 2014 was largely due to an
increase of $70.7 million net proceeds received for early terminations and modifications of commodity derivative contracts, a
net increase of $26.4 million in working capital, a change in fair value of performance unit awards and a change in other
noncurrent liabilities and an increase of $24.5 million in cash settlements received for matured derivatives and an increase of
$11.9 million in DD&A.
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, despite the August 2013 sale of the Anadarko Basin properties as well as increases 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 the variability of oil
and natural gas prices and production levels. 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."
Cash flows used in investing activities
Net cash used in investing activities increased $1.1 billion from 2013 to 2014 and is mainly attributable to (i)
increased capital expenditures for oil and natural gas properties and midstream service assets during the year ended December
31, 2014, (ii) significant leasehold acquisitions during the year ended December 31, 2014, which are included in the "Oil and
natural gas properties" line item below, and (iii) proceeds from our Anadarko Basin Sale in the prior period, which offset the
total cash flows used in investing activities for the year ended ended December 31, 2013.
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.
Our cash used in investing activities for the periods presented are summarized in the table below:
(in thousands)
Capital expenditures:
For the years ended December 31,
2014
2013
2012
Acquisitions of oil and natural gas properties ....................................................
Acquisition of mineral interests .........................................................................
Oil and natural gas properties.............................................................................
Midstream service assets ....................................................................................
Other fixed assets ...............................................................................................
Investment in equity method investee ..................................................................
Proceeds from dispositions of capital assets, net of costs ....................................
Net cash used in investing activities ................................................................
$
(6,493) $
(7,305)
(1,251,757)
(60,548)
(27,444)
(55,164)
1,750
$ (1,406,961) $
(33,710) $
—
(702,349)
(24,409)
(16,257)
(3,287)
450,128
(329,884) $
(20,496)
—
(895,312)
(16,241)
(8,755)
—
53
(940,751)
Capital expenditure budget
Our board of directors approved a capital expenditure budget of approximately $525.0 million for calendar year 2015,
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. Subject to financing alternatives, we may also increase our capital expenditures
significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our
projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of
financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals,
the availability of rigs, reduction of service costs, contractual obligations, internally generated cash flow and other factors both
66
within and outside our control. Additionally, we have been in active discussions with service providers to align service costs
with the current decline in commodity prices. For additional information on the impact of changing prices on our financial
position, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
Cash flows provided by financing activities
For the year ended December 31, 2014, net cash provided by financing activities was the result of our issuance of our
January 2022 Notes of $450.0 million, borrowings of $300.0 million on our Senior Secured Credit Facility and proceeds from
the exercise of employee stock options of $1.9 million. These cash inflows were partially offset by payments for debt issuance
costs totaling $7.8 million and the purchase of treasury stock to satisfy employee tax withholding obligations that arose upon
the lapse of restrictions on restricted stock totaling $4.2 million.
For the year ended December 31, 2013, net cash provided by financing activities was the result of net proceeds from
our August 2013 equity 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 debt issuance costs totaling $3.0 million and the purchase of treasury stock to satisfy employee tax withholding obligations
that arose 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 May 2022 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.
Our cash provided by financing activities for the periods presented is summarized in the table below.
(in thousands)
Borrowings on Senior Secured Credit Facility .................................................
Payments on Senior Secured Credit Facility.....................................................
Issuance of January 2022 Notes........................................................................
Issuance of May 2022 Notes .............................................................................
Proceeds from issuance of common stock, net of offering costs ......................
Proceeds from exercise of employee stock options ..........................................
Purchase of treasury stock.................................................................................
Payments for debt issuance costs ......................................................................
Net cash provided by financing activities ...............................................
For the years ended December 31,
2014
$
300,000
$
—
450,000
—
—
1,885
(4,242)
(7,791)
739,852
$
$
2013
230,000
(395,000)
—
—
298,104
2,050
(2,083)
(2,987)
130,084
$
$
2012
360,000
(280,000)
—
500,000
—
—
—
(10,803)
569,197
Debt
As of December 31, 2014, we were a party only to our Senior Secured Credit Facility and the indentures governing
our Senior Unsecured Notes.
Senior Secured Credit Facility. As of December 31, 2014, our Senior Secured Credit Facility, which matures
November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion, an aggregate elected
commitment of $900.0 million and $300.0 million outstanding.
Principal amounts borrowed under our 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, in each case, plus an applicable margin based on the ratio of the outstanding amount on our 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%.
The borrowing base under our Senior Secured Credit Facility is subject to a semi-annual redetermination based on the
lenders' evaluation of our oil and natural gas reserves. The lenders have the right to call for an interim redetermination of the
borrowing base once between any two redetermination dates and in other specified circumstances. A continued decline in oil
and natural gas prices may materially and adversely impact our borrowing base in future borrowing base redeterminations,
which could trigger repayment obligation under our Senior Secured Credit Facility to the extent our outstanding loans under the
Senior Secured Credit Facility exceed the redetermined borrowing base.
67
As of December 31, 2014, 2013 and 2012, borrowings outstanding under our Senior Secured Credit Facility totaled
$300.0 million, zero and $165.0 million, respectively. As of February 25, 2015, $435.0 million were outstanding under our
Senior Secured Credit Facility and the amount available for borrowings was $465.0 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. Our Senior Secured
Credit Facility contains both financial and non-financial covenants. We were in compliance with these covenants as of
December 31, 2014, 2013 and 2012.
As of December 31, 2014, we were subject to the following 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, depletion, depreciation, 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 various non-financial 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 that 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, 2014, 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, 2014, 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 our 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;
68
•
•
•
•
•
•
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 that 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 our 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, 2014.
Senior Unsecured Notes. On January 23, 2014, we completed an offering of $450.0 million aggregate principal
amount of 5 5/8% senior unsecured notes due 2022. The January 2022 Notes will mature on January 15, 2022 and bear an
interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year,
commencing July 15, 2014. The January 2022 Notes are guaranteed, jointly and severally, on a senior unsecured basis by
Laredo Midstream, GCM and certain of our future restricted subsidiaries. Our January 2022 Notes were issued under and are
governed by an indenture dated January 23, 2014 (the "2014 Indenture"), among Laredo and Wells Fargo Bank, National
Association, as trustee. The 2014 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 January 2022 Notes may be accelerated in certain circumstances upon an
event of default as set forth in the 2014 Indenture.
On April 27, 2012, we completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior
unsecured notes due 2022. The May 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, commencing November 1, 2012. Our May
2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Midstream,
GCM and certain of our future restricted subsidiaries. Our May 2022 Notes were issued under and are governed by an
indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 Indenture"), among Laredo and Wells
Fargo Bank, National Association, as trustee. 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 May 2022 Notes may be accelerated in certain
circumstances upon an event of default as set forth in the 2012 Indenture.
On January 20, 2011 and October 19, 2011, we completed the offerings of $350.0 million principal amount and $200.0
million principal amount, respectively, of 9 1/2% senior unsecured notes due 2019. 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. Our 2019 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by
Laredo Midstream, GCM and certain of our future restricted subsidiaries. Our 2019 Notes were issued under and are governed
by an indenture dated January 20, 2011, among Laredo and Wells Fargo Bank, National Association, as trustee (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 Notes may be accelerated in certain circumstances upon an event of
default as set forth in the 2011 Indenture.
Refer to Note 4 of our audited consolidated financial statements included elsewhere in this Annual Report for further
discussion of the January 2022 Notes, May 2022 Notes, 2019 Notes and our Senior Secured Credit Facility.
As of February 25, 2015, we had a total of $1.5 billion of Senior Unsecured Notes outstanding.
69
Obligations and commitments
We had the following significant contractual obligations and commitments that will require capital resources as of
December 31, 2014:
(in thousands)
Senior Secured Credit Facility(1) ................................
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
$
— $
— $
300,000
$
— $
300,000
114,438
35,924
5,166
1,156
2,477
2,738
18,359
228,875
752,750
1,105,468
2,201,531
9,287
4,009
1,937
6,319
2,313
—
—
339
1,193
5,540
—
—
—
—
27,912
9,509
—
—
45,211
9,514
32,198
23,845
5,051
18,359
$
180,258
$
252,740
$ 1,059,822
$ 1,142,889
$ 2,635,709
___________________________________________________________________________
(1) Includes outstanding principal amount at December 31, 2014. This table does not include future commitment fees,
interest expense or other fees on our Senior Secured Credit Facility because it is a floating rate instrument and we
cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
As of December 31, 2014, the principal on our Senior Secured Credit Facility is due on November 4, 2018.
(2) Values presented include both our principal and interest obligations.
(3) As of December 31, 2014, we had several drilling rigs under term contracts which expire during 2015 and 2016. 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 10.c 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 2.m to our audited consolidated financial statements included elsewhere in this
Annual Report.
(6) See Note 10.a 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 February 3, 2012 performance awards were paid in January 2015. The payout of the February 15,
2013 Performance Awards is dependent upon our relative total shareholder return performance against a set of peers
and will be paid out, if at all, in 2016. See Note 5.e to our audited consolidated financial statements included
elsewhere in this Annual Report for additional discussion of our performance units.
(8) See Note 14 to our audited consolidated financial statements included elsewhere in this Annual Report for a discussion
of our equity method investee. See Note 16.c to our audited consolidated financial statements included elsewhere in
this Annual Report for further information regarding a capital call that occurred after December 31, 2014.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our audited
consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our 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
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
70
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 audited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and
assumptions used in preparation of our audited consolidated financial statements.
In management's opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the
choice of accounting method for oil and natural gas activities, (ii) estimation of oil and natural gas reserve quantities and
standardized measure of future net revenues, (iii) revenue recognition, (iv) fair value of assets acquired and liabilities assumed
in an acquisition, (v) impairment of oil and natural gas properties, (vi) asset retirement obligations, (vii) valuation of derivatives
and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (ix) estimation of
income taxes. Management's judgments and estimates in these areas are based on information available from both internal and
external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from
the estimates as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the year ended
December 31, 2014. See Note 2.b to our audited 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 evaluated reserves, in which case a gain or loss is recognized. The
costs of unevaluated 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 evaluated 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
On an annual basis, 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 that
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. As there is a ready market for oil and natural gas, we sell the majority of production
soon after it is produced at various locations.
71
Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a
fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is
probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when we take title to the
products and has risks and rewards of ownership.
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 14 to our audited consolidated financial statements
included elsewhere in this Annual Report for a discussion of our unconsolidated VIE.
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 evaluated reserves, less
any related income tax effects. For the years ended December 31, 2014, 2013 and 2012, 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. For midstream service assets, this is
the period in which the asset is placed in service. 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 for oil and natural gas properties the capitalized cost is depreciated on the unit of production
method or for midstream service assets depreciated over its useful life. The accretion expense is recorded in the line item
"Accretion of asset retirement obligations" in our audited 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 audited 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
72
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. During
the year ended December 31, 2014, we began capitalizing a portion of stock-based compensation for employees who are
directly involved in the acquisition, exploration and development of our properties into the full cost pool. Capitalized stock-
based compensation is included as an addition to "Oil and natural gas properties" in the audited consolidated balance sheets.
As there are inherent uncertainties related to these performance criteria 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 5 of our audited consolidated financial statements included elsewhere in this Annual
Report for additional information regarding our stock-based compensation.
Performance unit and performance share 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
in "General and administrative" expense in our audited consolidated statements of operations with the corresponding liabilities
recorded in the "Other current liabilities" and "Other noncurrent liabilities" line items of our audited consolidated balance
sheets.
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 awards may not accurately reflect the amount ultimately earned
by the member of management. Refer to Note 5 of our audited consolidated financial statements included elsewhere in this
Annual Report for additional information regarding our performance unit awards.
Our performance share awards are accounted for as equity awards. The fair value of the performance share awards
issued during 2014 was based on a projection of the performance of our stock price relative to our peer group utilized in a
forward-looking Monte Carlo simulation. The fair value of the performance share awards will not be re-measured after the
initial valuation of the awards and will be expensed on a straight-line basis over their three-year requisite service period.
Income taxes
As of December 31, 2014, and 2013, we had a deferred tax liability of $176.9 million and $12.7 million, respectively.
As part of the process of preparing the audited 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 audited consolidated balance sheet. We must then assess, using all available negative and positive 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 audited 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 evaluated oil and natural gas reserves;
73
•
•
•
our ability to use tax planning strategies, such as electing to capitalize intangible drilling costs as opposed to
expensing such costs;
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 2014, 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 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, 2014 and 2013, 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 eight to twelve 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, 2014, we had charitable contribution carry-forwards of $3.6 million, which will begin to expire in
2015. 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 $1.3 million has been recorded against the related
deferred tax asset.
Based on our analysis, we determined as of December 31, 2014 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. The
corresponding deferred tax asset also is measured on the grant date and recognized over the service period. The related tax
deduction is measured on the vesting date for restricted stock and on the exercise date for stock options. 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, 2014 and 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess
tax benefits have been recognized, therefore all shortfalls have been recognized in income tax expense.
Recent accounting pronouncements
In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue
recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive
Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize
revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which
the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires
significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing
and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that
requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The
74
standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the
periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period
presented in the financial statements, including additional disclosures of the standard's application impact to individual
financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016,
including interim periods within that reporting period. We are currently evaluating this standard and our existing revenue
recognition policies to determine what impact this guidance will have on our audited consolidated financial statements upon
adoption.
In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of
components of an entity. The guidance changes the criteria for reporting discontinued operations, including raising the
threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional
disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria.
The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted
for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. We
elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and the adoption did not have an effect
on our audited consolidated financial statements.
In July 2013, the FASB issued guidance on the presentation of an unrecognized tax benefit when a net operating loss
carry-forward, a similar tax loss or a tax credit carry-forward exists. The guidance requires an unrecognized tax benefit, or a
portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net
operating loss carry-forward, a similar tax loss or a tax credit carry-forward except when (i) a net operating loss carry-forward,
a similar tax loss or a tax credit carry-forward is not available at the reporting date under the tax law of the applicable
jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of
the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such
purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and
should not be combined with deferred tax assets. We adopted this guidance on January 1, 2014, and the adoption did not have
an effect on our audited 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, 2012 through the year ended December 31, 2014. Although the impact of inflation
has been insignificant in recent years, it continues to be a factor in the U.S. economy and historically, we have experienced
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."
75
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," in our case, refers to the risk of loss arising
from adverse changes in oil and natural gas prices and in 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 and
puts 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 audited consolidated statements of operations included elsewhere in this Annual Report.
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, 2014, 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
397,596
$
234,272
$
As of December 31, 2014 and 2013, the fair values of our open derivatives contracts were $312.3 million and $82.1
million, respectively. Refer to Notes 7 and 8 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, 2014, we had $300.0
million outstanding on our Senior Secured Credit Facility. Our 2019 Notes, January 2022 Notes and May 2022 Notes bear fixed
interest rates and we had $550.0 million (excluding the remaining premium of $1.3 million), $450.0 million and $500.0 million
outstanding, respectively, as of December 31, 2014, as shown in the table below.
Expected maturity date
$ — $ — $ — $ — $ 550.0
2016
2017
2015
2018
(in millions except for interest rates)
2019 Notes - fixed rate...................................
Average interest rate ......................................
January 2022 Notes - fixed rate .....................
Average interest rate ......................................
May 2022 Notes - fixed rate ..........................
Average interest rate ......................................
Senior Secured Credit Facility - variable rate $ — $ — $ — $ 300.0
Average interest rate ......................................
—%
—%
—%
—%
—%
—%
—%
—%
—%
—%
—%
—% 1.790%
—%
2019
Thereafter
Total
—% 9.500%
$ — $ 550.0
—% 9.500%
—%
—%
5.625% 5.625%
—%
7.375% 7.375%
$ — $ — $ 300.0
—%
—% 1.790%
$ — $ — $ — $ — $ — $ 450.0
$ 450.0
$ — $ — $ — $ — $ — $ 500.0
$ 500.0
Counterparty and customer credit risk
Our principal exposures to credit risk are through (i) receivables from derivatives ($312.4 million as of December 31,
2014), (ii) receivables resulting from the sale of our oil and natural gas production ($57.1 million as of December 31, 2014),
which we market to energy marketing companies and refineries, (iii) joint interest receivables ($33.8 million as of
December 31, 2014) and (iv) receivables from midstream product sales ($18.9 million as of December 31, 2014).
We are subject to credit risk due to the concentration of (i) our oil and natural gas receivables with several significant
customers and (ii) our midstream service product sale receivable with one significant customer. On occasion we 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.
76
We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of
our derivative counterparties, who also are or were lenders in our Senior Secured Credit Facility. The terms of the ISDA
Agreements provide the counterparties and us with rights of offset upon the occurrence of defined acts of default by either a
counterparty or us 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 9 of our audited consolidated financial statements included elsewhere in this Annual Report for
additional disclosures regarding credit risk.
77
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, 2014 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.
78
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, 2014, 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 2013 "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, 2014.
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, 2014. The report, which expresses an unqualified
opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2014, is included in
this Item under the heading "Report of Independent Registered Public Accounting Firm."
79
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. (a Delaware corporation) and
subsidiaries (the "Company") as of December 31, 2014, based on criteria established in the 2013 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, 2014, based on criteria established in the 2013 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, 2014, and our report dated
February 26, 2015 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 26, 2015
80
Item 9B. Other Information
None.
81
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, 2014.
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, 2014.
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, 2014.
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, 2014.
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, 2014.
82
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
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).
Amended and Restated Indenture, dated as of June 24, 2014, among Laredo Petroleum, Inc., Laredo
Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee (incorporated by reference
to Exhibit 4.2 of Laredo's Quarterly Report on Form 10-Q (File No. 001-35380) filed on August 7, 2014).
4.3*
Sixth Supplemental Indenture, dated as of December 3, 2014, among Laredo Petroleum, Inc., Garden City
Minerals, LLC, Laredo Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee.
4.4
4.5
4.6
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).
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 (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).
Amended and Restated Supplemental Indenture, dated as of June 24, 2014, among Laredo Petroleum, Inc.,
Laredo Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee (incorporated by
reference to Exhibit 4.3 of Laredo's Quarterly Report on Form 10-Q (File No. 001-35380) filed on August 7,
2014).
83
Exhibit Number
4.7*
Fourth Supplemental Indenture, dated as of December 3, 2014, among Laredo Petroleum, Inc., Garden City
Minerals, LLC, Laredo Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee.
Description
4.8
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).
4.9*
First Supplemental Indenture, dated as of December 3, 2014, among Laredo Petroleum, Inc., Garden City
Minerals, LLC, Laredo Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee.
10.1
10.2
10.3
10.4
10.5
10.6#
10.7#
10.8#
10.9#
10.10#
10.11#
10.12
10.13#
10.14*
10.15
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).
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).
Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 8, 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 May 8, 2014).
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).
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).
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.
Non-Exclusive Aircraft Lease Agreement, dated January 1, 2015 between Lariat Ranch, LLC and Laredo
Petroleum, Inc.
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).
84
Exhibit Number
21.1*
23.1*
List of Subsidiaries of Laredo Petroleum, Inc.
Consent of Grant Thornton LLP.
Description
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.
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.
85
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 26, 2015
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, Kenneth E. Dornblaser and Michael T. Beyer, 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.
86
Signatures
/s/ Randy A. Foutch
Randy A. Foutch
/s/ Richard C. Buterbaugh
Richard C. Buterbaugh
/s/ Michael T. Beyer
Michael T. Beyer
/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. Scoggins
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
officer)
Vice President - Controller and Chief
Accounting Officer (principal accounting
officer)
Director, President and Chief
Operating Officer
Director
Director
Director
Director
Director
Director
Director
Director
Date
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
2/26/2015
87
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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, 2014 and 2013.....................................................................................
Consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 ....................................
Consolidated statements of stockholders' equity for the years ended December 31, 2014, 2013 and 2012.....................
Consolidated statements of cash flows for the years ended December 31, 2014, 2013 and 2012....................................
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-42
F-47
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. (a Delaware corporation) and
subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. 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. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and
their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on criteria established in the 2013
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our report dated February 26, 2015, expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 26, 2015
F-2
Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
December 31,
2014
2013
Assets
Current assets:
Cash and cash equivalents .......................................................................................................................................... $
29,321
$
198,153
Accounts receivable, net .............................................................................................................................................
Derivatives ..................................................................................................................................................................
Deferred income taxes ................................................................................................................................................
Other current assets.....................................................................................................................................................
Total current assets................................................................................................................................................
126,929
194,601
—
14,402
365,253
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties.................................................................................................................................................
4,446,781
Unevaluated properties not being amortized ...........................................................................................................
Midstream service assets.............................................................................................................................................
Other fixed assets........................................................................................................................................................
Total property and equipment...............................................................................................................................
Less accumulated depletion, depreciation, amortization and impairment..................................................................
Net property and equipment..................................................................................................................................
Derivatives .....................................................................................................................................................................
Debt issuance cost, net...................................................................................................................................................
Investment in equity method investee............................................................................................................................
Other assets, net .............................................................................................................................................................
342,731
117,052
56,165
4,962,729
(1,608,647)
3,354,082
117,788
28,463
58,288
8,675
77,318
15,806
3,634
12,698
307,609
3,276,578
208,085
51,704
32,832
3,569,199
(1,364,875)
2,204,324
79,726
25,933
5,913
255
Total assets...................................................................................................................................................... $
3,932,549
$
2,623,760
Liabilities and stockholders' equity
Current liabilities:
Accounts payable ........................................................................................................................................................ $
39,008
$
Accrued payable - affiliates ........................................................................................................................................
Undistributed revenue and royalties ...........................................................................................................................
Accrued capital expenditures......................................................................................................................................
Derivatives ..................................................................................................................................................................
Deferred income taxes ................................................................................................................................................
Other current liabilities ...............................................................................................................................................
Total current liabilities..........................................................................................................................................
Long-term debt...............................................................................................................................................................
Derivatives .....................................................................................................................................................................
Deferred income taxes ...................................................................................................................................................
Asset retirement obligations ..........................................................................................................................................
Other noncurrent liabilities ............................................................................................................................................
3,443
65,438
148,241
115
71,191
97,589
425,025
1,801,295
—
105,754
31,042
6,232
16,002
3,489
35,124
116,328
10,795
—
72,231
253,969
1,051,538
2,680
16,293
21,478
5,546
Total liabilities ......................................................................................................................................................
2,369,348
1,351,504
Commitments and contingencies ...................................................................................................................................
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2014 and 2013...
—
—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 143,686,491 and 142,671,436 issued, at
December 31, 2014 and 2013, respectively ................................................................................................................
Additional paid-in capital ...........................................................................................................................................
Retained earnings (accumulated deficit).....................................................................................................................
Total stockholders' equity .....................................................................................................................................
1,437
1,309,171
252,593
1,563,201
Total liabilities and stockholders' equity......................................................................................................... $
3,932,549
$
1,427
1,283,809
(12,980)
1,272,256
2,623,760
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 .................................................................................................................... $
737,203
$
664,844
$
583,569
For the years ended December 31,
2014
2013
2012
Midstream service revenue ................................................................................................................
Sales of purchased oil ........................................................................................................................
Total revenues...........................................................................................................................
Costs and expenses:
Lease operating expenses...................................................................................................................
Production and ad valorem taxes .......................................................................................................
Midstream service expense ................................................................................................................
Natural gas volume commitment - affiliates......................................................................................
Costs of purchased oil........................................................................................................................
Drilling rig fees ..................................................................................................................................
General and administrative ................................................................................................................
Accretion of asset retirement obligations ..........................................................................................
Depletion, depreciation and amortization ..........................................................................................
Impairment expense ...........................................................................................................................
Total costs and expenses...........................................................................................................
Operating income..................................................................................................................................
Non-operating income (expense):
Gain (loss) on derivatives:
2,245
54,437
793,885
96,503
50,312
5,429
2,552
53,967
527
106,044
1,787
246,474
3,904
567,499
226,386
413
—
325
—
665,257
583,894
79,136
42,396
3,368
891
—
—
89,696
1,475
233,944
—
450,906
214,351
67,325
37,637
2,614
—
—
—
62,106
1,200
241,072
—
411,954
171,940
8,800
(412)
—
Commodity derivatives, net ............................................................................................................
327,920
79,902
Interest rate derivatives, net ............................................................................................................
Income (loss) from equity method investee.......................................................................................
—
(192)
(24)
29
Interest expense..................................................................................................................................
(121,173)
(100,327)
(85,572)
Interest and other income...................................................................................................................
Write-off of debt issuance costs.........................................................................................................
Loss on disposal of assets, net ...........................................................................................................
Non-operating income (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........................................................................
294
(124)
(3,252)
203,473
429,859
(164,286)
(164,286)
265,573
—
163
(1,502)
(1,508)
(23,267)
191,084
(74,507)
(74,507)
116,577
1,423
Net income ............................................................................................................................................ $
265,573
$
118,000
$
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:
1.88
—
1.88
1.85
—
1.85
$
$
$
$
0.88
0.01
0.89
0.87
0.01
0.88
$
$
$
$
59
—
(51)
(77,176)
94,764
(33,003)
(33,003)
61,761
(107)
61,654
0.49
—
0.49
0.48
—
0.48
Basic...................................................................................................................................................
Diluted................................................................................................................................................
141,312
143,554
132,490
134,378
126,957
128,171
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Laredo Petroleum, Inc.
Consolidated statements of stockholders' equity
(in thousands)
Treasury Stock
(at cost)
Shares
Amount
Retained
earnings
(accumulated
deficit)
(192,634) $
—
—
—
61,654
(130,980)
—
—
(4) $
—
—
—
—
(4)
—
—
$
8
—
—
—
—
8
—
—
$
Additional
paid-in
capital
951,375
(9)
2
10,056
—
961,424
(15)
2
Common Stock
$
Shares
127,617
932
(251)
—
—
128,298
1,469
(229)
—
(95)
104
Amount
1,276
9
(2)
—
—
1,283
15
(2)
—
(1)
1
—
(2,086)
2,049
95
(103)
—
(2,083)
2,087
—
13,000
130
297,974
124
—
—
142,671
1,234
(148)
—
(166)
95
—
—
143,686
$
1
—
—
1,427
12
(1)
—
(2)
1
—
—
1,437
3,028
21,433
—
1,283,809
(12)
1
—
(4,240)
1,884
27,729
—
$ 1,309,171
—
—
—
—
—
—
—
—
—
—
—
—
—
—
166
(166)
—
—
—
— $
(4,242)
4,242
—
—
—
— $
Total
760,013
—
—
10,056
61,654
831,723
—
—
(2,083)
—
2,050
298,104
3,029
21,433
118,000
1,272,256
—
—
(4,242)
—
1,885
27,729
265,573
$ 1,563,201
—
—
—
—
—
—
118,000
(12,980)
—
—
—
—
—
—
265,573
252,593
Balance, December 31, 2011...........
Restricted stock awards...................
Restricted stock forfeitures..............
Stock-based compensation ..............
Net income ......................................
Balance, December 31, 2012...........
Restricted stock awards...................
Restricted stock forfeitures..............
Vested restricted stock exchanged
for tax withholding ..........................
Retirement of treasury stock ...........
Exercise of employee stock options
Equity issuance, net of offering
costs.................................................
Equity issued for acquisition, net of
offering costs ...................................
Stock-based compensation ..............
Net income ......................................
Balance, December 31, 2013...........
Restricted stock awards...................
Restricted stock forfeitures..............
Vested restricted stock exchanged
for tax withholding ..........................
Retirement of treasury stock ...........
Exercise of employee stock options
Stock-based compensation ..............
Net income ......................................
Balance, December 31, 2014...........
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
For the years ended December 31,
2013
2012
2014
Cash flows from operating activities:
Net income ................................................................................................................................................ $
Adjustments to reconcile net income to net cash provided by operating activities:
265,573
$
118,000
$
61,654
Deferred income tax expense ..............................................................................................................
Depletion, depreciation and amortization ...........................................................................................
Bad debt expense.................................................................................................................................
Impairment expense ............................................................................................................................
Non-cash stock-based compensation, net of amount capitalized ........................................................
Accretion of asset retirement obligations............................................................................................
Mark-to-market on derivatives:
Gain on derivatives, net....................................................................................................................
Cash settlements received 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 debt issuance costs....................................................................................................
Write-off of debt issuance costs ..........................................................................................................
Amortization of October 2011 Notes premium...................................................................................
Loss on disposal of assets, net.............................................................................................................
Cash settlement of performance unit awards ......................................................................................
Other....................................................................................................................................................
(Increase) decrease in accounts receivable..........................................................................................
Increase in other assets ........................................................................................................................
Increase (decrease) in accounts payable..............................................................................................
Increase (decrease) in undistributed revenues and royalties ...............................................................
Increase in other accrued liabilities .....................................................................................................
Increase in other noncurrent liabilities ................................................................................................
Increase in fair value of performance unit awards ..............................................................................
Net cash provided by operating activities .....................................................................................
164,286
246,474
342
3,904
23,079
1,787
(327,920)
28,241
76,660
220
(7,419)
5,137
124
(243)
3,252
—
838
(49,953)
(16,688)
23,006
30,314
23,837
2,825
601
498,277
Cash flows from investing activities:
Capital expenditures:
Acquisitions of oil and natural gas properties ........................................................................................
Acquisition of mineral interests .............................................................................................................
Oil and natural gas properties.................................................................................................................
Midstream service assets ........................................................................................................................
Other fixed assets ...................................................................................................................................
Investment in equity method investee .......................................................................................................
Proceeds from dispositions of capital assets, net of costs .........................................................................
Net cash used in investing activities..............................................................................................
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility..........................................................................................
Payments on Senior Secured Credit Facility.............................................................................................
Issuance of January 2022 Notes ................................................................................................................
Issuance of May 2022 Notes .....................................................................................................................
Proceeds from issuance of common stock, net of offering costs ..............................................................
Proceeds from exercise of employee stock options...................................................................................
Purchase of treasury stock.........................................................................................................................
Payments for debt issuance costs ..............................................................................................................
Net cash provided by financing activities .....................................................................................
Net (decrease) increase in cash and cash equivalents ..................................................................................
Cash and cash equivalents, beginning of period ..........................................................................................
Cash and cash equivalents, end of period..................................................................................................... $
(6,493)
(7,305)
(1,251,757)
(60,548)
(27,444)
(55,164)
1,750
(1,406,961)
300,000
—
450,000
—
—
1,885
(4,242)
(7,791)
739,852
(168,832)
198,153
29,321
$
75,288
234,571
653
—
21,433
1,475
(79,878)
3,745
6,008
462
(10,277)
5,023
1,502
(222)
1,508
(2,080)
(37)
6,825
(7,438)
(32,581)
(941)
16,458
499
4,733
364,729
(33,710)
—
(702,349)
(24,409)
(16,257)
(3,287)
450,128
(329,884)
230,000
(395,000)
—
—
298,104
2,050
(2,083)
(2,987)
130,084
164,929
33,224
198,153
$
32,949
243,649
—
—
10,056
1,200
(8,388)
24,910
—
668
(6,118)
4,816
—
(202)
52
—
19
(9,705)
(414)
2,665
9,221
7,849
98
1,797
376,776
(20,496)
—
(895,312)
(16,241)
(8,755)
—
53
(940,751)
360,000
(280,000)
—
500,000
—
—
—
(10,803)
569,197
5,222
28,002
33,224
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, 2014, 2013 and 2012
Note 1—Organization
The Company (defined below) is an independent energy company focused on the acquisition, exploration and
development 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 at the time of the internal corporate reorganization, Laredo Gas, changed its
name to Laredo Midstream Services, LLC ("Laredo Midstream"). 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 October 24, 2014, Laredo formed Garden City Minerals, LLC ("GCM"), a Delaware limited liability company, for
the purpose of holding its mineral interests. GCM is wholly owned by Laredo. GCM and Laredo Midstream (together, the
"Guarantors") guarantee all of Laredo's debt instruments.
In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2014, refers to
Laredo, Laredo Midstream and GCM collectively; (ii) when used for historical periods from December 31, 2013 to October 23,
2014, refers to Laredo and Laredo Midstream collectively; (iii) when used for historical periods from December 19, 2011 to
December 30, 2013, refers to Laredo and its subsidiaries, collectively; and (iv) 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.
Note 2—Basis of presentation and significant accounting policies
a. 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
Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting
rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the
Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See
Note 14 for additional discussion of the Company's equity-method investment. The accompanying consolidated financial
statements have been prepared in accordance with accounting principles generally accepted in the United States of America
("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts.
The Company reports as one business segment, which explores for, develops and produces oil and natural gas. Unless otherwise
indicated, the information in these notes relates to the Company's continuing operations.
b. Use of estimates in the preparation of consolidated financial statements
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires
management 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.
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
F-7
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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.
c. Reclassifications
Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2014
presentation. These reclassifications had no impact to previously reported total assets, total liabilities, net income, stockholders'
equity or cash flows. See Note 3.f for a discussion regarding discontinued operations.
d. Cash and cash equivalents
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. 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 (see Note 9).
e. 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, oil and natural gas sales and purchased oil and other
product 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. Additionally, as the operator
of the majority of its wells, the Company has 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 amounts
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.
Accounts receivable consist of the following components as of December 31:
(in thousands)
Oil and natural gas sales ...........................................................................................................
Joint operations, net(1) ...............................................................................................................
Purchased oil and other product sales.......................................................................................
Other .........................................................................................................................................
Total........................................................................................................................................
2014
2013
$
$
57,070
33,808
18,917
17,134
$
126,929
$
57,647
16,629
—
3,042
77,318
______________________________________________________________________________
(1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.8 million and
$0.7 million as of December 31, 2014 and 2013, respectively.
f. 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, in prior periods the Company entered into interest rate
derivatives.
F-8
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
Derivatives are recorded at fair value and are included net on the consolidated balance sheets as assets or liabilities.
The Company nets the fair value of derivatives by counterparty on 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 (see Note 7 and 8).
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 7).
g. Other current liabilities
Other current liabilities consist of the following components as of December 31:
(in thousands)
Accrued interest payable..........................................................................................................
Lease operating expense payable.............................................................................................
Accrued compensation and benefits ........................................................................................
Other accrued liabilities ...........................................................................................................
Total other current liabilities..................................................................................................
$
$
2014
2013
37,689
$
11,963
13,034
34,903
97,589
$
25,885
10,637
16,711
18,998
72,231
h. 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 $342.7
million and $208.1 million of such costs were excluded from the amortization base as of December 31, 2014 and 2013,
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 $1.6
billion and $1.3 billion for the years ended December 31, 2014 and 2013, respectively. Depletion expense for oil and natural
gas properties was $237.1 million, $228.0 million and $237.1 million for the years ended December 31, 2014, 2013 and 2012,
respectively. There were no impairments recorded for the years ended December 31, 2014, 2013 and 2012. Depletion per barrel
of oil equivalent for the Company's oil and natural gas properties was $20.21, $20.34 and $20.98 for the years ended
December 31, 2014, 2013 and 2012, respectively.
The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the
depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company
capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the
unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated 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 evaluated 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 proved 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 evaluated oil and
F-9
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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, 2014, 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, 2014 of $4.25 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, 2014 of $91.48 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 evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2014.
Changes in prices, 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, 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 evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013.
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 evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.
i. Midstream service assets
Midstream service assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery
stations, water storage and treatment facilities and their related asset retirement cost. The oil and natural gas pipeline gathering
assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of accumulated
depreciation. See Note 2.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded
using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant
betterments or renewals, 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 midstream service assets was $4.3 million, $1.5 million and $0.8 million for the years ended
December 31, 2014, 2013 and 2012, respectively.
Midstream service assets consist of the following as of December 31:
(in thousands)
Midstream service assets..........................................................................................................
Less accumulated depreciation ................................................................................................
Total, net................................................................................................................................
$
$
2014
2013
117,052
(8,590)
108,462
$
$
51,704
(4,404)
47,300
j. 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 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 significant betterments
or renewals, 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 $5.1 million, $4.4 million and $3.1 million for the years ended
December 31, 2014, 2013 and 2012, respectively.
F-10
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
Other fixed assets consist of the following as of December 31:
(in thousands)
Computer hardware and software ............................................................................................
Vehicles....................................................................................................................................
Leasehold improvements .........................................................................................................
Aircraft.....................................................................................................................................
Production equipment ..............................................................................................................
Furniture and fixtures...............................................................................................................
Other ........................................................................................................................................
Depreciable total ....................................................................................................................
Less accumulated depreciation and amortization ....................................................................
Depreciable total, net ..........................................................................................................
Land .........................................................................................................................................
Total, net ...........................................................................................................................
2014
2013
$
13,495
$
11,370
7,802
6,867
4,952
2,577
1,750
5,490
42,933
(13,820)
29,113
13,232
$
42,345
$
4,542
3,520
4,952
403
1,342
2,565
28,694
(11,156)
17,538
4,138
21,676
k. Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among
other things, 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. 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, 2014 or 2013.
l. Debt issuance costs
Debt issuance 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 $7.8 million of debt issuance
costs during the year ended December 31, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below).
The Company capitalized $3.0 million of debt issuance costs during the year ended December 31, 2013. The Company had
total debt issuance costs of $28.5 million and $25.9 million, net of accumulated amortization of $19.4 million and $14.2
million, as of December 31, 2014 and 2013, respectively.
As a result of changes in the borrowing base of the Senior Secured Credit Facility due to the issuance of the January
2022 Notes, the Company wrote-off $0.1 million of debt issuance costs during the year ended December 31, 2014. During the
year ended December 31, 2013, $1.5 million of debt issuance costs were written-off as a result of changes in the borrowing base
of the Senior Secured Credit Facility due to the Anadarko Basin Sale. No debt issuance costs were written off in the year ended
December 31, 2012. See Notes 4 and 3 for definition of and information regarding the Senior Secured Credit Facility, the
January 2022 Notes and the Anadarko Basin Sale (defined below), respectively.
Future amortization expense of debt issuance costs as of December 31, 2014 is as follows:
(in thousands)
2015......................................................................................................................................................................
2016......................................................................................................................................................................
2017......................................................................................................................................................................
2018......................................................................................................................................................................
2019......................................................................................................................................................................
Thereafter .............................................................................................................................................................
Total ...................................................................................................................................................................
$
5,295
5,361
5,433
5,222
2,110
5,042
$
28,463
F-11
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
m. 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 depletion, or for midstream service asset retirement cost through depreciation, of the
associated 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) estimated remaining life of midstream service assets, (iv) estimated removal and/or
remediation costs for midstream service assets, (v) future inflation factors and (vi) 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 obligation liability for continuing and discontinued
operations as of December 31:
(in thousands)
Liability at beginning of year....................................................................................................
Liabilities added due to acquisitions, drilling, midstream service asset construction and
other ..........................................................................................................................................
Accretion expense .....................................................................................................................
Liabilities settled upon plugging and abandonment .................................................................
Liabilities removed due to sale of property ..............................................................................
Revision of estimates ................................................................................................................
Liability at end of year............................................................................................................
2014
2013
$
21,743
$
21,505
6,370
1,787
(450)
—
2,748
2,709
1,475
(226)
(7,801)
4,081
$
32,198
$
21,743
n. Fair value measurements
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 assets and liabilities approximate
their fair values. See Note 4 for fair value disclosures related to the Company's debt obligations. The Company carries its
derivatives at fair value. See Note 7 and Note 8 for details regarding the fair value of the Company's derivatives.
o. 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. Upon acquisition, this treasury stock is retired.
p. 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. For natural gas sales, 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 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,
F-12
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
net of any allowance from the overproduced working interest owner. The Company is also subject to natural gas pipeline
imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the
owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2014 or
2013. During the year ended December 31, 2013, the majority of the Company's natural gas producer 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.
Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a
fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is
probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes
title to the products and has risks and rewards of ownership.
q. 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)
Fees received for the operation of jointly-owned oil and natural gas properties.
For the years ended December 31,
2014
2013
2012
$
3,265
$
3,398
$
2,335
r. Compensation awards
Stock-based compensation expense is recognized in "General and administrative" in the Company's consolidated
statements of operations over the awards' vesting periods and is based on their grant date fair value. The Company utilizes the
closing stock price on the date of grant, less an expected forfeiture rate, 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 values of the
performance share awards and performance unit awards. On January 1, 2014, the Company began capitalizing a portion of
stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil
and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and
natural gas properties" in the consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock
awards, restricted stock option awards, performance share awards and performance unit awards.
s. 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 6 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,
2014, 2013 or 2012.
F-13
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
t. Long-lived assets, materials and supplies and line-fill
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.
Materials and supplies are comprised of equipment used in developing oil and natural gas properties and are included
in "Other current assets" and "Other assets, net" on the consolidated balance sheets. They are carried at the lower of cost or
market ("LCM"). During the year ended December 31, 2014, the Company reduced materials and supplies by $1.8 million in
order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the consolidated statements of
operations. The Company determined an LCM adjustment was not necessary for materials and supplies during the years ended
December 31, 2013 or 2012.
Pipelines in which we have a minimum volume of product in the system to enable the system to operate is known as
line-fill, and is generally not available to be withdrawn from the system until the expiration of the contract. Beginning in 2014,
the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the
weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The LCM adjustment
is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the year ended December
31, 2014, the Company recorded an LCM adjustment of $2.1 million related to its line-fill, which is included in "Impairment
expense" in the consolidated statements of operations.
u. 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 $150, $255 and $627 of capitalized interest,
respectively..................................................................................................
For the years ended December 31,
2014
2013
2012
$
104,936
$
95,622
$
74,638
The following presents the supplemental disclosure of non-cash investing and financing information for the periods
presented:
(in thousands)
Change in accrued capital expenditures ......................................................
Change in accrued capital contribution to equity method investee.............
Capitalized asset retirement cost .................................................................
Capitalized stock-based compensation........................................................
Equity issued in connection with acquisition ..............................................
$
$
$
$
$
For the years ended December 31,
2014
2013
2012
$
31,913
(2,597) $
$
9,118
4,650
$
— $
(5,284) $
$
2,597
6,790
$
— $
3,029
$
30,590
—
7,379
—
—
Note 3—Acquisitions and divestitures
The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties 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 evaluated and unevaluated 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 unevaluated properties, the discounted future net revenues of probable and possible reserves are reduced by
additional risk-weighting factors.
F-14
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
a. 2014 acquisition of leasehold interests
During the year ended December 31, 2014, the Company completed a material acquisition of leasehold interests
totaling 8,156 net acres in the Midland Basin, primarily within the Company's core development area, for $192.5 million. The
acquisition was accounted for as an acquisition of assets.
b. 2014 acquisition of mineral interests
On February 25, 2014, the Company completed the acquisition of the mineral interests underlying 278 net acres in
Glasscock County, Texas in the Permian Basin for $7.3 million. These mineral interests entitle the Company to receive royalty
interests on all production from this acreage with no additional future capital or operating expenses required. As such, the
acquisition was accounted for as an acquisition of assets.
c. 2014 acquisitions of evaluated and unevaluated oil and natural gas properties
On June 11, 2014, the Company completed the acquisition of evaluated and unevaluated oil and natural gas properties,
totaling 460 net acres, located in Reagan County, Texas for $4.7 million, net of closing adjustments. On June 23, 2014, the
Company completed the acquisition of evaluated and unevaluated oil and natural gas properties, totaling 24 net acres, located in
Glasscock County, Texas for $1.8 million. The results of operations prior to June 2014 do not include results from these
acquisitions.
d. 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.
e. 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.
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
2012
$
59,631
46,357
84,616
89,602
(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" during the year ended December 31,
2013.
F-15
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following represents operating results from discontinued operations for the periods presented:
(in thousands)
Revenues:
For the years ended December 31,
2013
2012
Midstream service revenue...................................................................................................
Total revenues from discontinued operations ..................................................................
$
$
4,020
4,020
Cost and expenses:
Midstream service expense, net ...........................................................................................
Depreciation and amortization.................................................................................................
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............................................................................
$
1,189
627
1,816
—
2,204
(781)
1,423
$
4,186
4,186
1,769
2,577
4,346
(1)
(161)
54
(107)
f. Summary of 2013 and 2012 business combinations
The following presents the Company's 2013 and 2012 business combination activities. For further discussion of the
estimates of fair value of the acquired assets and liabilities of these acquisitions see Note C in the Company's 2013 Annual
Report on Form 10-K.
(in thousands)
Accounting
treatment
Cash
consideration
Common
stock issued(2)
September 6, 2013 acquisition of evaluated and unevaluated oil and natural gas
properties(1) ..............................................................................................................
July 12, 2012 acquisition of evaluated and unevaluated oil and natural gas
properties..................................................................................................................
Acquisition
method
Acquisition
method
$
$
33,710
20,496
$
$
3,029
—
_____________________________________________________________________________
(1) The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated
properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.
(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 were
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 8.
Note 4—Debt
a. Interest expense
The following amounts have been incurred and charged to interest expense for the periods presented:
(in thousands)
Cash payments for interest ..................................................................................
Amortization of debt issuance costs and other adjustments................................
Change in accrued interest...................................................................................
Interest costs incurred .......................................................................................
Less capitalized interest.......................................................................................
Total interest expense .....................................................................................
For the years ended December 31,
2014
2013
2012
$
105,086
$
95,877
$
75,265
4,433
11,804
121,323
(150)
121,173
$
4,926
(221)
100,582
(255)
100,327
$
$
4,940
5,994
86,199
(627)
85,572
F-16
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
b. January 2022 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8%
senior unsecured notes due 2022 (the "January 2022 Notes"), and entered into an Indenture (the "Indenture") among Laredo,
Laredo Midstream as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 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 January 2022 Notes are fully and unconditionally guaranteed,
jointly and severally, on a senior unsecured basis by Laredo Midstream, GCM and certain of the Company's future restricted
subsidiaries, subject to certain automatic customary releases, including the sale, disposition, or transfer of all of the capital
stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a
restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture,
designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance
with the Indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively,
the "Releases").
The January 2022 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 January 2022 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 used the net
proceeds of the offering for general working capital purposes.
Laredo will have the option to redeem all or part of the January 2022 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, the Company may
redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to
100% of the principal amount of the January 2022 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, the Company may on one or
more occasions redeem up to 35% of the aggregate principal amount of the January 2022 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 January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal
amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within
180 days of the closing date of each such equity offering.
In connection with the closing of the offering of the January 2022 Notes, the Company entered into a registration
rights agreement with the several initial purchasers named in the registration rights agreement, pursuant to which the Company
filed a registration statement with the Securities and Exchange Commission ("SEC") that became effective with respect to an
offer to exchange the January 2022 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. The offer to exchange the January 2022 Notes
for substantially identical notes registered under the Securities Act was launched on April 22, 2014 with all notes exchanged on
May 22, 2014.
c. May 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 "May 2022 Notes"). The May 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,
commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a
senior unsecured basis by Laredo Midstream, GCM and certain of the Company's future restricted subsidiaries, subject to
certain Releases.
The May 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,
entering into transactions with affiliates and limitations on asset sales. Indebtedness under the May 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 May 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
F-17
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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 May 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 May 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 May 2022 Notes, plus any accrued and
unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the May 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 May 2022 Notes upon a
change of control triggering event.
d. 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, the Company completed an offering of an additional $200.0 million 9 1/2%
senior unsecured notes due 2019 (the "October 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 Laredo Midstream, GCM and certain of the Company's future restricted subsidiaries, subject to
certain Releases.
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 has the option to redeem the 2019 Notes, in whole or in part, 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. Laredo may also be required to
make an offer to purchase the 2019 Notes upon a change of control triggering event.
e. Senior Secured Credit Facility
As of December 31, 2014, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured
Credit Facility"), which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of
$1.15 billion and an aggregate elected commitment of $900.0 million with $300.0 million outstanding and was subject to an
interest rate of 1.94%. 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, which ranges
from 0.5% to 1.5% 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, which ranges from 1.5% to 2.5%, 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.
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 evaluated 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;
F-18
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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 for all periods presented.
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, 2014 or 2013.
f. Fair value of debt
The following table presents the carrying amounts and fair values of the Company's debt instruments for the periods
presented:
(in thousands)
2019 Notes(1) ......................................................................................
January 2022 Notes............................................................................
May 2022 Notes.................................................................................
Senior Secured Credit Facility ...........................................................
Total value of debt...........................................................................
December 31, 2014
December 31, 2013
Carrying
value
551,295
$
$
450,000
500,000
300,000
Fair
value
550,000
396,014
467,529
300,279
Carrying
value
551,538
$
$
—
Fair
value
615,313
—
500,000
549,375
—
—
$ 1,801,295
$ 1,713,822
$ 1,051,538
$ 1,164,688
________________________________________________________________________
(1) The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $1.3 million and $1.5
million as of December 31, 2014 and 2013, respectively.
The fair values of the debt outstanding on the 2019 Notes, the January 2022 Notes and the May 2022 Notes were
determined using the December 31, 2014 and 2013 quoted market price (Level 1) for each respective instrument. The fair value
of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2014 was estimated utilizing pricing models
for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.
Note 5—Employee compensation
The Company has 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, performance share awards, performance unit awards and other
awards. The LTIP provides for the issuance of 10.0 million shares.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service
period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted
for as equity instruments and its performance unit awards are accounted for as liability awards. Stock-based compensation is
included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began
capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and
development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an
addition to "Oil and natural gas properties" in the consolidated balance sheets.
a. Restricted stock awards
All restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements.
Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, the awarded shares are
forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by
reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to
officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then 20% annually
thereafter, (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in
year three, (iv) fully on the first anniversary date of the grant and (v) fully on the third anniversary date of the grant. Restricted
stock awards granted to non-employee directors vest fully on the first anniversary date of the grant.
F-19
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following table reflects the outstanding restricted stock awards for the years ended December 31, 2014, 2013 and
2012:
(in thousands, except for weighted-average grant date fair values)
Outstanding at December 31, 2011.....................................................................................
Granted .............................................................................................................................
Forfeited............................................................................................................................
Vested(1).............................................................................................................................
Outstanding at December 31, 2012 ....................................................................................
Granted .............................................................................................................................
Forfeited............................................................................................................................
Vested(2).............................................................................................................................
Outstanding at December 31, 2013 ....................................................................................
Granted .............................................................................................................................
Forfeited............................................................................................................................
Vested(2).............................................................................................................................
Outstanding at December 31, 2014 ....................................................................................
_____________________________________________________________________________
Restricted
stock awards
Weighted-average
grant date
fair value (per
award)
911
$
932
$
(251) $
(397) $
$
1,195
1,469
$
(229) $
(636) $
$
1,799
1,234
$
(148) $
(680) $
$
2,205
1.14
22.90
15.61
1.03
15.06
18.17
18.47
18.69
19.17
25.68
22.56
19.13
22.63
(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 awards could result in federal and state income tax expense or benefit related to
the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 6 for
additional discussion regarding the tax impact of vested restricted stock awards.
For grants after the IPO, 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, 2014, unrecognized stock-based compensation expense related to
restricted stock awards was $27.6 million. Such cost is expected to be recognized over a weighted-average period of 1.46 years.
F-20
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
b. Restricted stock option awards
Restricted stock options awards granted under the LTIP vest and are exercisable in four equal installments on each of
the four anniversaries of the date of the grant. The following table reflects the stock option award activity for the years ended
December 31, 2014, 2013 and 2012:
(in thousands, except for weighted-average exercise price and contractual term)
Outstanding at December 31, 2011......................................................
Granted ..............................................................................................
Forfeited ............................................................................................
Outstanding at December 31, 2012......................................................
Granted ..............................................................................................
Exercised(1) ........................................................................................
Expired or canceled ...........................................................................
Forfeited ............................................................................................
Outstanding at December 31, 2013......................................................
Granted ..............................................................................................
Exercised(1) ........................................................................................
Expired or canceled ...........................................................................
Forfeited ............................................................................................
Outstanding at December 31, 2014......................................................
Vested and exercisable at end of period(2)............................................
Vested, exercisable, and expected to vest at end of period(3) ...............
_____________________________________________________________________________
Restricted
stock option
awards
Weighted-average
exercise price
(per option)
Weighted-average
remaining
contractual term
(years)
— $
$
603
(144) $
$
459
$
1,019
(104) $
(12) $
(133) $
$
1,229
336
$
(95) $
(30) $
(73) $
$
1,367
324
1,336
$
$
—
24.11
24.11
24.11
17.34
20.79
24.11
19.88
19.32
25.60
19.93
21.15
19.68
20.76
20.29
20.76
—
10
10
10
9.13
8.75
—
—
8.82
9.16
7.73
—
—
8.17
7.68
8.16
(1) The exercise of stock option awards could result in federal and state income tax expense or benefits related to the
difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock
option award when exercised. See Note 6 for additional discussion regarding the tax impact of exercised stock option
awards.
(2) The vested and exercisable options as of December 31, 2014 had no aggregate intrinsic value.
(3) The vested, exercisable and expected to vest options as of December 31, 2014 had no aggregate intrinsic value.
The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option
awards 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 equity-based awards requires judgment, including estimating the expected term that stock
option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2014, unrecognized stock-
based compensation related to restricted option awards was $8.2 million. Such cost is expected to be recognized over a
weighted-average period of 2.32 years.
F-21
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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 stock option ...................................................................
$
1.88%
1.19%
1.14%
6.25 years
6.25 years
6.25 years
53.21%
13.41
$
58.89%
9.67
$
59.98%
13.52
February 27, 2014
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 limited or no exercise history at the time of valuation relating to terminations and modifications,
expected option life assumptions were developed using the simplified method in accordance with GAAP.
(3) The Company utilized a peer historical look-back, which was weighted with the Company's own volatility, in order 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
Less than one ................................................................................................
One ...............................................................................................................
Two...............................................................................................................
Three.............................................................................................................
Four ..............................................................................................................
Incremental percentage of
option exercisable
Cumulative percentage of
option exercisable
—%
25%
25%
25%
25%
—%
25%
50%
75%
100%
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the
Company for one 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 a stock option award shall expire upon termination of employment,
and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by
reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following
termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of
employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the
termination of the option holder's employment or service by the Company for cause.
c. Performance share awards
The performance share awards granted to management on February 27, 2014 ("Performance Share Awards") are subject
to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was
utilized in order to determine the fair value of these awards at the date of grant. The Company has determined the Performance
Share Awards are equity awards and is recognizing the associated expense on a straight-line basis over the three-year requisite
service period of the awards. These awards will be settled in stock at the end of the requisite service period based on the
achievement of certain performance criteria.
The Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares
earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met. During the
year ended December 31, 2014, 271,667 performance shares were awarded and all remain outstanding at December 31, 2014. As
of December 31, 2014, unrecognized stock-based compensation related to the Performance Share Awards was $5.4 million. Such
cost is expected to be recognized over a weighted-average period of 2.16 years.
F-22
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The assumptions used to estimate the fair value of the Performance Share Awards are as follows:
Risk-free rate(1)................................................................................................................................................
Dividend yield.................................................................................................................................................
Expected volatility(2) .......................................................................................................................................
Laredo stock closing price as of February 27, 2014 .......................................................................................
Fair value per performance share....................................................................................................................
$
$
0.63%
—%
38.21%
25.60
28.56
______________________________________________________________________________
(1) The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on
the grant date.
(2) The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected
volatility.
d. Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
(in thousands)
Restricted stock award compensation ...................................................................
Restricted stock option award compensation ........................................................
Restricted performance share award compensation ..............................................
Total stock-based compensation .........................................................................
Less amounts capitalized in oil and natural gas properties ...................................
Net stock-based compensation expense............................................................
3,639
2,108
27,729
(4,650)
23,079
$
4,349
—
21,433
—
8,496
1,560
—
10,056
—
$
21,433
$
10,056
For the years ended December 31,
2014
2013
2012
$
21,982
$
17,084
$
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.
e. Performance unit awards
The performance unit awards issued to management on February 15, 2013 ("2013 Performance Unit Awards") and on
February 3, 2012 ("2012 Performance Unit Awards") are subject to a combination of market and service vesting criteria. A
Monte Carlo simulation prepared by an independent third party was utilized in order to determine the fair values of these awards
at the date of grant and to re-measure the fair values 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's stock price and
the stock price volatilities of a group of peer companies that have been determined to be most representative of the Company's
expected volatility. 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 of these
awards for each period 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. As there are inherent uncertainties related to these
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.
The 2013 Performance Unit Awards have a performance period of January 1, 2013 to December 31, 2015 and are
expected to be paid in the first quarter of 2016 if the performance criteria are met. The 2012 Performance Unit Awards had a
performance period of January 1, 2012 to December 31, 2014 and were paid at $100 per unit in the first quarter of 2015. There
were no performance unit awards issued or outstanding during the year ended December 31, 2011.
F-23
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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 ........................................................................................
Vested...................................................................................................................................
Outstanding at December 31, 2014 ........................................................................................
_______________________________________________________________________________
2013 Performance
Unit Awards
2012 Performance
Unit Awards (2)
—
—
—
—
58
(4)
(10)
44
—
44
—
49
(2)
47
—
(9)
(11)
27
(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.
(2) The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria
were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.
The assumptions used to estimate the fair value of the 2013 Performance Unit Awards as of December 31, 2014 are as
follows:
Risk-free rate(1) .....................................................................................................................................................
Dividend yield ......................................................................................................................................................
Expected volatility(2).............................................................................................................................................
Laredo closing price as of December 31, 2014 ....................................................................................................
$
0.25%
—%
64.76%
10.35
_______________________________________________________________________________
(1) The risk-free rate uses the one-year zero-coupon yield derived from the Treasury Constant Maturities yield curve.
(2) The expected volatility is calculated using daily stock returns based on the one year historical volatility for LPI.
The fair value of the 2013 Performance Unit Awards as of December 31, 2014 was $3.5 million. The liability related to
the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million and represents the cash payment made in the first
quarter of 2015. The fair values 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.
The following has been recorded to performance unit award compensation expense for the periods presented:
(in thousands)
2013 Performance Unit Award compensation expense.......................................................
2012 Performance Unit Award compensation expense.......................................................
Total performance unit award compensation expense .....................................................
$
$
For the years ended December 31,
2014
2013
2012
409
192
601
$
$
2,863
1,870
4,733
$
$
—
1,797
1,797
Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is recognized in
"General and administrative" in the Company's consolidated statements of operations, and the corresponding liabilities are
included in "Other current liabilities" and "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 determination of the 2013
Performance Unit Awards, there is risk that the recorded performance unit compensation may not accurately reflect the amount
ultimately earned by the members of management.
F-24
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
f. 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 the cost recognized for the Company's defined contribution plan for the periods presented:
(in thousands)
Contributions......................................................................................................................
For the years ended December 31,
2014
2013
2012
$
2,202
$
1,886
$
1,293
Note 6—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:
For the years ended December 31,
2014
2013
2012
Federal.....................................................................................................................
State.........................................................................................................................
$
— $
—
— $
—
—
—
Deferred taxes:
Federal.....................................................................................................................
State.........................................................................................................................
Income tax expense...............................................................................................
(147,445)
(16,841)
$ (164,286) $
(64,034)
(10,473)
(74,507) $
(31,390)
(1,613)
(33,003)
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,
2014
2013
2012
Continuing operations .............................................................................................
Discontinued operations..........................................................................................
Comprehensive provision for income taxes .........................................................
$ (164,286) $
—
$ (164,286) $
(74,507) $
(781)
(75,288) $
(33,003)
54
(32,949)
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 35% for the year ended December 31, 2014 and 34% for the
years ended December 31, 2013 and 2012 to pre-tax earnings as a result of the following:
For the years ended December 31,
(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 .............................................................
Other items ................................................................................................................
Income tax expense .................................................................................................
2014
$ (150,450) $
(11,099)
(509)
(266)
(1,139)
(823)
$ (164,286) $
2013
(64,969) $
(7,532)
(1,070)
(559)
(63)
(314)
(74,507) $
2012
(32,219)
(102)
(1,177)
—
583
(88)
(33,003)
F-25
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The effective tax rate for the Company's continuing operations was 38%, 39% and 35% for the years ended December
31, 2014, 2013 and 2012, 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.
The impact of significant discrete items is separately recognized in the year in which they occur. The vesting of certain
restricted stock awards 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 exercise of stock option awards 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 tax impact resulting from vestings of restricted stock
awards and exercise of option awards are discrete items. During the years ended December 31, 2014 and 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 years ended December 31, 2014 and 2013, certain restricted stock options were exercised. There
were no comparable taxable vestings of stock awards or the exercise of stock options during the year ended December 31,
2012. The income tax deduction related to the intrinsic value of the options 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,
such shortfalls are included in income tax expense attributable to continuing operations.
The following table presents the tax impact of these shortfalls for the periods presented:
(in thousands)
Vesting of restricted stock .........................................................................................
Exercise of restricted stock options...........................................................................
Tax impact of shortfalls...........................................................................................
$
$
For the years ended December 31,
2014
2013
2012
112
158
270
$
$
425
150
575
$
$
—
—
—
Significant components of the Company's deferred tax liabilities as of December 31 are as follows:
(in thousands)
Oil and natural gas properties, midstream service assets and other fixed assets ..............................
Net operating loss carry-forward ......................................................................................................
Derivatives ........................................................................................................................................
Stock-based compensation ................................................................................................................
Accrued bonus...................................................................................................................................
Capitalized interest............................................................................................................................
Other..................................................................................................................................................
Gross deferred tax liability .............................................................................................................
Valuation allowance..........................................................................................................................
Net deferred tax liability.................................................................................................................
2014
2013
$ (424,712) $ (278,735)
284,890
(30,859)
6,578
353,724
(121,365)
10,718
3,256
3,049
(316)
(175,646)
(1,299)
$ (176,945) $
3,740
2,099
(240)
(12,527)
(132)
(12,659)
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:
(in thousands)
Deferred tax asset..............................................................................................................................
Deferred tax liability .........................................................................................................................
Net deferred tax liability.................................................................................................................
2014
2013
$
— $
(176,945)
$ (176,945) $
3,634
(16,293)
(12,659)
F-26
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates
as of December 31, 2014:
(in thousands)
2026..........................................................................................................................................................................
2027..........................................................................................................................................................................
2028..........................................................................................................................................................................
2029..........................................................................................................................................................................
2030..........................................................................................................................................................................
Thereafter.................................................................................................................................................................
Total.......................................................................................................................................................................
$
2,741
38,651
228,661
101,932
82,948
549,892
$ 1,004,825
The Company had federal net operating loss carry-forwards totaling $1.0 billion and state of Oklahoma net operating
loss carry-forwards totaling $92.7 million as of December 31, 2014. These carry-forwards begin expiring in 2026 and continue
through 2034, as presented in the table above. As of December 31, 2014, 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, 2014, 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.
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, 2014, the Company had suspended additional paid-in capital credits of $4.5 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 $4.5 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, 2014, a full valuation allowance of $1.3 million was recorded against the deferred
tax asset related to the Company's charitable contribution carry-forward of $3.6 million.
The Company filed its 2013 federal and Oklahoma income tax returns during the year ended December 31, 2014. As a
result, the Company recognized an aggregate expense from tax return related items, which is a discrete item, of $0.6 million for
the year ended December 31, 2014 and is included in income tax expense attributable to continuing operations for the period.
The tax expense impact of the prior-year return to provision true-up was $2.4 million for year ended December 31, 2013. There
was no comparative amount for the year ended December 31, 2012.
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 file a single return. The Company's income tax
returns for the years 2011 through 2014 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.
Note 7—Derivatives
a. Commodity derivatives
The Company engages in derivative transactions such as collars, swaps and puts 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, 2014, the
Company had 31 open derivative contracts with financial institutions which extend from January 2015 to December 2017.
None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the
F-27
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are
reported on the consolidated statements of operations in the respective "Gain (loss) on derivatives" amounts.
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 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. 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.
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.
During the first quarter of 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 in accordance with the normal purchase and normal sale scope exemption. Once modified to
settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope
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.
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
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
$ 7.05
September 2013 - December 2013
$ — 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-28
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following represents cash settlements received (paid) for matured derivatives and for early terminations and
modifications of derivatives for the periods presented:
(in thousands)
Cash settlements received for matured commodity derivatives........................
Cash settlements paid for matured interest rate swaps......................................
Early terminations and modification of commodity derivatives received(1) .....
Cash settlements received for derivatives, net................................................
$
$
_________________________________________________________________
For the years ended December 31,
2014
2013
2012
28,241
—
76,660
104,901
$
$
4,046
(301)
6,008
9,753
$
$
27,025
(2,115)
—
24,910
(1) 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.
The following table summarizes open positions as of December 31, 2014, and represents, as of such date, derivatives
in place through December 2017 on annual production volumes:
Year
2015
Year
2016
Year
2017
—
— $
1,573,800
84.82
2,556,000
80.00
93.77
4,129,800
90.36
4,129,800
81.84
—
—
—
—
2,263,000
80.00
100.00
2,263,000
100.00
2,263,000
80.00
—
—
—
$
$
$
$
$
$
$
Oil positions(1):
Puts:
Hedged volume (Bbl) .........................................................................................
Weighted-average price ($/Bbl) .........................................................................
Swaps:
Hedged volume (Bbl) .........................................................................................
Weighted-average price ($/Bbl) .........................................................................
Collars:
Hedged volume (Bbl) .........................................................................................
Weighted-average floor price ($/Bbl).................................................................
Weighted-average ceiling price ($/Bbl) .............................................................
Totals:
Total volume hedged with ceiling price (Bbl)....................................................
Weighted-average ceiling price ($/Bbl) .............................................................
Total volume hedged with floor price (Bbl).......................................................
Weighted-average floor price ($/Bbl).................................................................
456,000
75.00
672,000
96.56
6,557,020
79.81
95.40
7,229,020
95.51
7,685,020
80.99
$
$
$
$
$
$
$
$
$
$
$
$
Natural gas positions(2):
Collars:
Hedged volume (MMBtu) ..................................................................................
Weighted-average floor price ($/MMBtu) .........................................................
Weighted-average ceiling price ($/MMBtu) ......................................................
28,600,000
3.00
5.96
$
$
18,666,000
3.00
5.60
$
$
______________________________________________________________
(1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West
Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each
month ("WTI NYMEX").
(2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation
period.
b. 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. In prior periods, interest rate derivative agreements were 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") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference,
F-29
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
and conversely, the counterparties were required to pay the Company if LIBOR was 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 were recorded in current earnings. In prior years, 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, 2014.
c. Balance sheet presentation
In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting
under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net
basis as "Derivatives" on the consolidated balance sheets. See Note 8.a for a summary of the fair value of derivatives on a gross
basis.
By using derivatives to hedge exposures to changes in commodity prices and interest rates, the Company exposes
itself to credit risk and market risk. For the Company, 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, thereby creating credit risk. The Company's counterparties are or originally
were 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 derivative
counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty,
(ii) entering into derivatives only with counterparties that 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.
Note 8—Fair value measurements
The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate
derivatives, at fair value. The fair value of derivatives is 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:
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, 2014, 2013 or 2012.
F-30
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
a. Fair value measurement on a recurring basis
The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net
presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as
of December 31, 2014 and 2013:
(in thousands)
As of December 31, 2014:
Assets .....................................................
Current:
Oil derivatives ...................................
Natural gas derivatives ......................
Oil deferred premiums.......................
Natural gas deferred premiums .........
Noncurrent:
Oil derivatives ...................................
Natural gas derivatives ......................
Oil deferred premiums.......................
Natural gas deferred premiums .........
Liabilities................................................
Current:
Oil derivatives ...................................
Natural gas derivatives ......................
Oil deferred premiums.......................
Natural gas deferred premiums .........
Noncurrent:
Oil derivatives ...................................
Natural gas derivatives ......................
Oil deferred premiums.......................
Natural gas deferred premiums .........
Net derivative position...................
$
$
Level 1
Level 2
Level 3
Total gross
fair value
Amounts
offset
Net fair value
presented on the
consolidated
balance sheets
$
— $ 190,303
$
— $ 190,303
$
— $
190,303
—
—
—
9,647
—
—
—
—
—
9,647
—
—
—
(4,653)
(696)
9,647
(4,653)
(696)
$
— $ 117,963
$
— $ 117,963
$
— $
117,963
—
—
—
3,646
—
—
—
—
—
3,646
—
—
—
(3,821)
—
3,646
(3,821)
—
$
— $
— $
— $
— $
— $
—
—
—
—
—
—
—
(4,768)
(696)
—
(4,768)
(696)
—
4,653
696
— $
— $
— $
— $
— $
—
—
(115)
—
—
—
—
—
—
3,821
—
$
— $
312,274
—
—
—
—
—
—
— $ 321,559
$
—
(3,821)
—
—
(3,821)
—
(9,285) $ 312,274
F-31
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
(in thousands)
As of December 31, 2013:
Assets .....................................................
Current:
Oil derivatives ...................................
Natural gas derivatives......................
Oil deferred premiums ......................
Natural gas deferred premiums .........
Noncurrent:
Oil derivatives ...................................
Natural gas derivatives......................
Oil deferred premiums ......................
Natural gas deferred premiums .........
Liabilities ...............................................
Current:
Oil derivatives ...................................
Natural gas derivatives......................
Oil deferred premiums ......................
Natural gas deferred premiums .........
Noncurrent:
Oil derivatives ...................................
Natural gas derivatives......................
Oil deferred premiums ......................
Natural gas deferred premiums .........
Net derivative position ..................
Level 1
Level 2
Level 3
Total Gross
Fair Value
Amounts
Offset
Net Fair Value
Presented on the
Consolidated
Balance Sheets
$
— $ 24,784
$
— $
24,784
$
—
—
—
166
—
—
—
—
—
166
—
—
(7,911) $
(235)
(537)
(461)
16,873
(69)
(537)
(461)
$
— $ 115,712
$
— $ 115,712
$ (35,593) $
80,119
—
—
—
491
—
—
—
—
—
491
—
—
(411)
—
(473)
$
$
$
— $ (11,782) $
—
— $ (33,948) $
—
(302)
—
—
(380)
—
—
—
—
—
—
— $ (11,782) $
—
(6,942)
(913)
(302)
(6,942)
(913)
7,911
$
235
537
461
— $ (33,948) $
—
(4,146)
(683)
(380)
(4,146)
(683)
82,057
35,593
$
411
—
473
— $ 94,741
$ (12,684) $
$
— $
80
—
(473)
(3,871)
(67)
(6,405)
(452)
1,645
31
(4,146)
(210)
82,057
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
each derivative contract's corresponding commodity index price, 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 1.69% 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 contract entered into which contained a deferred premium;
however, the valuation for the deferred premiums 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 a third-party valuation
of the deferred premiums for reasonableness.
F-32
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following table presents actual cash payments required for deferred premium contracts in place as of December
31, 2014, and for the calendar years following:
(in thousands)
2015..................................................................................................................................................................
2016..................................................................................................................................................................
2017..................................................................................................................................................................
2018..................................................................................................................................................................
Total................................................................................................................................................................
$
$
5,166
358
3,651
339
9,514
A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:
(in thousands)
Balance of Level 3 at beginning of period ................................................................
Change in net present value of deferred premiums for derivatives...........................
Total purchases and settlements:
Purchases.................................................................................................................
Settlements(1) ...........................................................................................................
Balance of Level 3 at end of period...........................................................................
$
$
___________________________________________________________________
For the years ended December 31,
2014
(12,684) $
(220)
2013
(24,709) $
(462)
2012
(18,868)
(668)
(3,800)
7,419
(9,285) $
—
12,487
(12,684) $
(11,291)
6,118
(24,709)
(1) The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were
settled net with the early terminated contracts from which they derive.
b. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For
purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based
on the use of internally developed cash-flow models. The accounting policies for impairment of oil and natural gas properties
are discussed in Note 2.h. 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 evaluated reserves and
other relevant data.
See Note 2.t for discussion of the Company's impairment of line-fill and materials and supplies in the year ended
December 31, 2014.
Note 9—Credit risk
The Company's oil and natural gas sales are made 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 oil
and natural gas 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; therefore, the credit risk associated with its derivative counterparties is
somewhat mitigated. See Note 7 for additional information regarding the Company's derivatives.
For the year ended December 31, 2014, the Company had two customers that accounted for 36.0% and 13.7% of total
oil and natural gas sales, with each customer accounting for 16.4% and 22.5%, respectively, of oil and natural gas sales
accounts receivable, and three other customers accounting for 13.5%, 12.5% and 11.6% of oil and natural gas sales accounts
receivable as of December 31, 2014. For the year ended December 31, 2013, the Company had three customers that accounted
F-33
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
for 28.3%, 11.7% and 11.7% of total oil and natural gas sales, 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 oil and natural gas sales.
As of December 31, 2014, the Company had two partners whose joint operations accounts receivable accounted for
20.5% and 13.2% of the Company's total joint operations accounts receivable. 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.
For the year ended December 31, 2014, the Company had one customer that accounted for 100% of total sales of
purchased oil, with the same customer accounting for 97.3% of purchased oil and other product sales receivable as of
December 31, 2014. There were no comparable sales of purchased oil for the years ended December 31, 2013 and 2012 and
correspondingly, there was no purchased oil and other product sales receivable as of December 31, 2013.
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 as of December 31, 2014, which exceeded the balance insured by the FDIC in the amount of $56.8
million. Management believes that the risk of loss is mitigated by the banks' reputation and financial position.
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 Targa and included
in the consolidated statements of operation for the periods presented:
(in thousands)
Net oil and natural gas sales .................................................................................................
For the years ended December 31,
2014
2013
2012
$ 96,100
$ 74,245
$ 71,916
The following table summarizes the amounts included in oil and natural gas sales receivable from Targa in the
consolidated balance sheets for the periods presented:
(in thousands)
Oil and natural gas sales receivable ..................................................................................................
December 31,
2014
2013
$
12,869
$
9,064
Note 10—Commitments and contingencies
a. Lease commitments
The Company leases equipment and office space under operating leases expiring on various dates through 2027.
Minimum annual lease commitments as of December 31, 2014 for the calendar years presented are:
(in thousands)
2015 ............................................................................................................................................................................
2016 ............................................................................................................................................................................
2017 ............................................................................................................................................................................
2018 ............................................................................................................................................................................
2019 ............................................................................................................................................................................
Thereafter....................................................................................................................................................................
Total..........................................................................................................................................................................
$
2,477
3,095
3,224
3,141
2,399
9,509
$
23,845
F-34
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
The following has been recorded to rent expense for the periods presented:
(in thousands)
Rent expense..............................................................................................................
For the years ended December 31,
2014
2013
2012
$
3,042
$
1,923
$
1,339
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. Rent expense is included in the
consolidated statements of operations in the "General and administrative" line item.
b. Litigation
From time to time the Company is involved in legal proceedings and/or may be 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.
c. Drilling contracts
The Company has committed to drilling contracts with various third parties in order to complete its various drilling
projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to the third party
should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon
early contract termination, especially if a significant number of such contracts were terminated early in their respective terms.
In the fourth quarter, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result of this
budget decrease, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5
million which are recorded for the year ended December 31, 2014 on the consolidated statements of operations as "Drilling rig
fees." No comparable amounts were recorded in the years ended December 31, 2013 or 2012. Future commitments of $45.2
million as of December 31, 2014 are not recorded in the accompanying consolidated balance sheets. Management does not
currently anticipate the early termination of any existing contracts in 2015 which would result in a substantial penalty.
d. 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 federal and state 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. These rules and regulations are frequently amended or reinterpreted; therefore the
Company is unable to predict the future cost or impact of complying with these regulations.
e. Other commitments
See Note 14 for discussion regarding commitments to the Company's non-consolidated variable interest entity ("VIE").
Note 11—Follow-on Offering
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. There were no comparable stock offerings in the years ended December 31, 2014 or 2012.
F-35
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
Note 12—Net income per share
Basic net income per share is computed by dividing net income by the weighted-average number of common shares
outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards,
Performance Share Awards and outstanding restricted stock options. For the year ended December 31, 2014, the Performance
Share Awards' total shareholder return was below their agreement's payout threshold, and therefore, the Performance Share
Awards were excluded from the calculation of diluted net income per share.
The effects of the Company's outstanding restricted stock options that were granted in February 2014 to purchase
336,140 shares of common stock at $25.60 per share and in February 2012 to purchase 280,626 shares of common stock at
$24.11 per share were excluded from the calculation of diluted net income per share for each of the years ended December 31,
2014, 2013 and 2012, because the exercise prices of these options were 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 restricted stock options that were granted in February 2013 to purchase
750,338 shares of common stock at $17.34 per share was excluded from the calculation of diluted net income per share for the
years ended December 31, 2014 and 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.
The following is the calculation of basic and diluted weighted-average common shares outstanding and net income per
share for the periods presented:
(in thousands, except for per share data)
Net income (numerator):
For the years ended December 31,
2014
2013
2012
Income from continuing operations—basic and diluted.................................
Income (loss) from discontinued operations, net of tax—basic and diluted ..
Net income—basic and diluted ....................................................................
$
$
265,573
—
265,573
$
$
116,577
1,423
118,000
$
$
61,761
(107)
61,654
Weighted-average common shares outstanding (denominator):
Weighted-average common shares outstanding—basic(1) ..............................
Non-vested restricted stock awards ................................................................
Weighted-average common shares outstanding—diluted............................
Net income per share:
Basic:
Income from continuing operations...............................................................
Income from discontinued operations, net of tax ..........................................
Net income per share ....................................................................................
Diluted:
Income from continuing operations...............................................................
Income from discontinued operations, net of tax ..........................................
Net income per share ....................................................................................
_______________________________________________________
141,312
2,242
143,554
132,490
1,888
134,378
126,957
1,214
128,171
$
$
$
$
1.88
—
1.88
1.85
—
1.85
$
$
$
$
0.88
0.01
0.89
0.87
0.01
0.88
$
$
$
$
0.49
—
0.49
0.48
—
0.48
(1) For the year ended December 31, 2013, weighted-average common 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.
Note 13—Recently issued accounting standards
In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition
standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific
guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new
guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or
services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative
F-36
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with
customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of
a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective
adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the
standard is applied only to the most current period presented in the financial statements, including additional disclosures of the
standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods
beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently
evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of
components of an entity. The guidance changes the criteria for reporting discontinued operations, including raising the
threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional
disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria.
The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted
for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The
Company elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and the adoption did not
have an effect on its consolidated financial statements.
In July 2013, the FASB issued guidance on the presentation of an unrecognized tax benefit when a net operating loss
carry-forward, a similar tax loss or a tax credit carry-forward exists. The guidance requires an unrecognized tax benefit, or a
portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net
operating loss carry-forward, a similar tax loss or a tax credit carry-forward except when (i) a net operating loss carry-forward,
a similar tax loss or a tax credit carry-forward is not available at the reporting date under the tax law of the applicable
jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of
the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such
purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and
should not be combined with deferred tax assets. The Company adopted this guidance on January 1, 2014, and the adoption did
not have an effect on its consolidated financial statements.
Note 14—Variable interest entity
An entity is referred to as a 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.
Laredo Midstream contributed $55.2 million and $3.3 million during the years ended December 31, 2014 and 2013,
respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its
wholly-owned subsidiaries (together "Medallion"). Laredo Midstream holds 49% of Medallion ownership units. Medallion was
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 Medallion's net income (loss) reflected in the consolidated statements of operations as "Income (loss) from equity
method investee" and the carrying amount reflected in the consolidated balance sheets as "Investment in equity method
investee."
F-37
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
During the year ended December 31, 2014, Medallion completed the construction of its pipeline from Garden City,
Texas to Colorado City, Texas and an extension from Medallion's Garden City Station to Midland and Upton counties, Texas.
As of December 31, 2014, Laredo Midstream has committed to fund an estimated $18.4 million to Medallion. See Note 16.c for
further information regarding a capital call that occurred after December 31, 2014.
As of December 31, 2014, the Company recorded a payable of $3.4 million related to its minimum volume
commitment to Medallion. As of December 31, 2013, the Company 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. These payables are reported on the consolidated balance sheets as "Accrued payable - affiliates."
The corresponding expense is reported on the consolidated statements of operations in the "Natural gas volume commitment -
affiliates" line item.
Note 15—Subsidiary guarantee
Laredo and the Guarantors have fully and unconditionally guaranteed the 2019 Notes, the January 2022 Notes, the
May 2022 Notes and the Senior Secured Credit Facility, subject to the Releases. 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 such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of
December 31, 2014 and 2013, and condensed consolidating statements of operations and condensed consolidating statements of
cash flows each for the years ended December 31, 2014, 2013 and 2012, present financial information for Laredo on a stand-
alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary
guarantors 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 and for GCM are recorded on Laredo's statements of financial position, statements of operations
and statements of cash flow as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not
restricted from making intercompany distributions to each other. During the year ended December 31, 2014, certain midstream
service assets were transferred from Laredo to Laredo Midstream at historical cost.
Condensed consolidating balance sheet
December 31, 2014
(in thousands)
Accounts receivable, net ....................................................................
Other current assets............................................................................
Total oil and natural gas properties, net.............................................
Total midstream service 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
$
107,860
238,300
3,196,231
Subsidiary
Guarantors
19,069
$
24
7,277
—
108,462
42,046
163,349
150,430
$ 3,898,216
$
38,453
$
$
354,217
140,817
1,801,295
1,563,434
299
58,288
4,496
197,915
555
31,800
2,211
—
163,349
$ 3,898,216
$
197,915
F-38
Intercompany
eliminations
$
— $
Consolidated
company
—
(233)
—
126,929
238,324
3,203,275
108,462
42,345
—
(163,349)
—
58,288
154,926
$ (163,582) $ 3,932,549
39,008
— $
$
—
—
386,017
143,028
— 1,801,295
(163,582)
1,563,201
$ (163,582) $ 3,932,549
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
Condensed consolidating balance sheet
December 31, 2013
(in thousands)
Accounts receivable, net ....................................................................
Other current assets............................................................................
Total oil and natural gas properties, net.............................................
Total midstream service 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
$
77,318
230,291
2,135,348
5,802
21,676
36,666
105,914
$ 2,613,015
$
12,216
$
$
231,008
45,997
1,051,538
1,272,256
Subsidiary
Guarantors
$
— $
Intercompany
eliminations
Consolidated
company
—
—
41,498
—
5,913
—
47,411
3,786
6,959
—
—
36,666
$
$
— $
77,318
—
230,291
— 2,135,348
—
—
(36,666)
—
47,300
21,676
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
$ 2,613,015
$
47,411
$
Condensed consolidating statement of operations
For the year ended December 31, 2014
(in thousands)
Total operating revenues....................................................................
Total operating costs and expenses....................................................
Income (loss) from operations.........................................................
Interest expense, net...........................................................................
Other, net............................................................................................
Income (loss) from continuing operations before income tax.........
Income tax expense............................................................................
Income (loss) from continuing operations.......................................
Net income (loss) ..........................................................................
Laredo
$
738,446
Subsidiary
Guarantors
63,944
$
Intercompany
eliminations
$
Consolidated
company
505,455
232,991
(120,879)
317,980
430,092
(164,286)
265,806
$
265,806
$
70,316
(6,372)
—
(339)
(6,711)
—
(6,711)
(6,711) $
(8,505) $
(8,272)
(233)
—
6,711
6,478
—
6,478
793,885
567,499
226,386
(120,879)
324,352
429,859
(164,286)
265,573
6,478
$
265,573
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............................................................................
Income from continuing operations.................................................
Income (loss) from discontinued operations, net of tax ..................
Net income ....................................................................................
F-39
Laredo
$
665,172
Subsidiary
Guarantors
8,824
$
Intercompany
eliminations
$
Consolidated
company
455,972
209,200
(100,164)
84,861
193,897
(74,507)
119,390
(1,390)
118,000
$
3,673
5,151
—
2,268
7,419
—
7,419
2,813
$
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
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
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............................................................................
Income from continuing operations.................................................
Income (loss) from discontinued operations, net of tax ..................
Net income ....................................................................................
Laredo
$
583,759
Subsidiary
Guarantors
10,285
$
Intercompany
eliminations
$
Consolidated
company
418,745
165,014
(85,513)
18,143
97,644
(33,003)
64,641
(2,987)
61,654
$
3,359
6,926
—
—
6,926
—
6,926
2,880
$
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 cash flows
For the year ended December 31, 2014
(in thousands)
Net cash flows provided (used) by operating activities .....................
Change in investments between affiliates..........................................
Capital expenditures and other...........................................................
Net cash flows provided by financing activities ................................
Net (decrease) increase in cash and cash equivalents .....................
Cash and cash equivalents at beginning of period...........................
Cash and cash equivalents at end of period.....................................
Laredo
$
496,955
(113,449)
(1,292,191)
739,852
(168,833)
198,153
120,160
(114,770)
—
1
—
1
Subsidiary
Guarantors
$
(5,389) $
Intercompany
eliminations
6,711
(6,711)
Consolidated
company
$
498,277
—
— (1,406,961)
739,852
—
(168,832)
198,153
—
—
$
29,320
$
$
— $
29,321
Condensed consolidating statement of cash flows
For the year ended December 31, 2013
Laredo
$
359,198
23,986
(348,339)
130,084
164,929
33,224
Subsidiary
Guarantors
15,763
$
(34,218)
18,455
—
—
—
Consolidated
company
Intercompany
eliminations
$
(10,232) $
10,232
364,729
—
(329,884)
130,084
164,929
33,224
—
—
—
—
$
198,153
$
— $
— $
198,153
(in thousands)
Net cash flows provided by operating activities ................................
Change in investments between affiliates..........................................
Capital expenditures and other...........................................................
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.....................................
F-40
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
December 31, 2014, 2013 and 2012
Condensed consolidating statement of cash flows
For the year ended December 31, 2012
(in thousands)
Net cash flows provided by operating activities ................................
Change in investments between affiliates..........................................
Capital expenditures and other...........................................................
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.....................................
Note 16—Subsequent events
a. Senior Secured Credit Facility
$
Laredo
373,362
(12,827)
(924,510)
569,197
5,222
28,002
Subsidiary
Guarantors
13,219
$
3,022
(16,241)
—
—
—
Consolidated
company
Intercompany
eliminations
$
(9,805) $
9,805
376,776
—
(940,751)
569,197
5,222
28,002
33,224
—
—
—
—
$
33,224
$
— $
— $
On January 8, January 15, February 5 and February 12, 2015, the Company borrowed $20.0 million, $45.0 million,
$15.0 million and $55.0 million on the Senior Secured Credit Facility, respectively. The outstanding balance under the Senior
Secured Credit Facility was $435.0 million at February 25, 2015.
b. Restructuring
Following the recent drop in oil and natural gas prices, in an effort to reduce costs and better position the Company for
ongoing efficient growth, on January 20, 2015, the Company committed to a company-wide restructuring and reduction in
force (the "RIF") that includes (i) the relocation of certain employees in the Company's Dallas, Texas area office to the
Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing our Dallas, Texas area office; (iii) a
workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The reduction in workforce
was communicated to employees on January 20, 2015 and was generally effective immediately. The relocation of Company
employees and the closing of the Company's Dallas, Texas area office are expected to be completed by June 1, 2015. The
Company's compensation committee approved the RIF and the severance package offered in connection with the RIF.
c. Medallion capital call
On February 17, 2015, the Company received a capital call from Medallion totaling $14.5 million, which represents
Laredo Midstream's remaining commitment for the extension from Medallion's Garden City Station to Midland and Upton
counties, Texas and a portion of the commitment for the southern extension from Medallion's Reagan Station further into
Reagan County, Texas.
d. New commodity derivative contracts
Subsequent to December 31, 2014, the Company entered into the following new commodity derivative contracts:
Aggregate
volumes
Swap
Price
Floor
Price
Ceiling
Price
Contract period
Oil (volumes in Bbl)
Price collar(1).................................
Basis swaps(2) ...............................
365,000
3,060,000
$ — $ 60.00
$ 80.00
$ (1.95) $ — $ —
January 2017 - December 2017
March 2015 - December 2015
_____________________________________________________________
(1) The associated commodity derivative will be settled based on the WTI NYMEX index oil price. There is a $1.0
million deferred premium associated with this contract.
(2) The associated oil basis swaps will be settled on the differential between the West Texas Intermediate Argus Americas
Crude Midland index oil price and the WTI NYMEX index oil price.
F-41
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2014, 2013 and 2012
Note 17—Supplemental oil and natural gas disclosures
a. Costs incurred in oil and natural gas property acquisition, exploration and development activities
Costs incurred in the acquisition, exploration 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,
2014
2013
2012
Evaluated.................................................................................................................
Unevaluated ............................................................................................................
Exploration(1) .............................................................................................................
Development costs(2)..................................................................................................
Total costs incurred...............................................................................................
$
3,873
$
9,652
$
16,925
9,925
242,284
27,087
48,763
3,693
93,266
1,049,317
654,452
839,118
$ 1,305,399
$
739,954
$
953,002
__________________________________________________________________________
(1) The Company acquired significant leasehold interests during the year ended December 31, 2014.
(2) The costs incurred for oil and natural gas development activities include $6.9 million, $6.8 million and $7.4 million in
asset retirement obligations for the years ended December 31, 2014, 2013 and 2012, respectively.
b. 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:
For the years ended December 31,
2014
2013
2012
Evaluated properties................................................................................................
Unevaluated properties ...........................................................................................
$ 4,446,781
$ 3,276,578
$ 2,993,266
342,731
208,085
159,946
Less accumulated depletion, depreciation and impairment ....................................
Net capitalized costs .............................................................................................
4,789,512
(1,586,237)
$ 3,203,275
3,484,663
(1,349,315)
$ 2,135,348
3,153,212
(1,121,273)
$ 2,031,939
The following table shows a summary of the oil and natural gas property costs not being amortized as of
December 31, 2014, by year in which such costs were incurred:
(in thousands)
Unevaluated properties...............................................
2014
2013
2012
2011 and
prior
Total
$
260,955
$
47,095
$
24,373
$
10,308
$
342,731
Unevaluated properties, which are not subject to amortization, are not individually significant and consist of costs for
acquiring oil and natural gas leaseholds where no evaluated 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-42
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2014, 2013 and 2012
c. 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,
2014
2013
2012
Oil and natural gas sales..........................................................................................
$
737,203
$
664,844
$
583,569
Production costs:
Lease operating expenses........................................................................................
Production and ad valorem taxes ............................................................................
96,503
50,312
79,136
42,396
67,325
37,637
146,815
121,532
104,962
Other costs:
Depletion and depreciation .....................................................................................
Accretion of asset retirement obligation .................................................................
Income tax expense(1) ..............................................................................................
Results of operations.............................................................................................
237,067
1,721
126,576
227,992
1,475
112,984
237,130
1,200
83,686
$
225,024
$
200,861
$
156,591
__________________________________________________________________________
(1) Income tax expense above is computed utilizing the statutory rate.
d. 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, 2014, 2013 and 2012. In accordance with SEC regulations, reserves as of
December 31, 2014, 2013 and 2012 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 ................................................................................
Production ..............................................................................................................
End of year................................................................................................................
Proved developed reserves:
Beginning of year ...................................................................................................
End of year .............................................................................................................
Proved undeveloped reserves:
Beginning of year ...................................................................................................
End of year .............................................................................................................
F-43
Year ended December 31, 2014
Oil
(MBbl)
Gas
(MMcf)
MBOE
111,498
(10,134)
45,554
173
(6,901)
140,190
37,878
56,975
73,620
83,215
552,702
(67,350)
185,909
498
(28,965)
642,794
203,082
291,493
349,620
351,301
203,615
(21,359)
76,539
256
(11,729)
247,322
71,725
105,557
131,890
141,765
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2014, 2013 and 2012
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 ..............................................................................................................
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, 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
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
For the year ended December 31, 2014, the Company's negative revision of 21,359 MBOE of previously estimated
quantities is primarily attributable to the removal of 26,017 MBOE due to the combined effect of the removal of 226 proved
undeveloped locations and the net effect of reinterpreting 345 undeveloped locations. The 226 locations that were removed
were comprised of vertical Wolfberry and horizontal laterals to better align with the proved developed producing wells. The
increase of 4,658 MBOE, which offsets the overall negative revision, is due to a combination of pricing, performance and other
changes. Extensions, discoveries and other additions of 76,539 MBOE during the year ended December 31, 2014, consisted of
34,782 MBOE primarily from the drilling of new wells during the year and 41,757 MBOE from 113 new horizontal proved
undeveloped locations added during the year. Purchases of minerals in place added 256 MBOE from acquisition of proved
reserves in the Permian Basin. The oil and natural gas reference prices used in computing the Company's reserves as of
December 31, 2014 were $91.48 per barrel of oil and $4.25 per MMBtu of natural gas before price differentials.
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 reinterpreting 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
F-44
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2014, 2013 and 2012
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 the Company's 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,
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 the Company's reserves as of December 31, 2012 were
$91.21 per barrel of oil and $2.63 per MMBtu of natural gas before price differentials.
e. 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 proved 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, 2014, 2013 and
2012 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 $91.48, $93.52 and
$91.21 per Bbl of oil and $4.25, $3.57 and $2.63 per MMBtu for December 31, 2014, 2013 and 2012, 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)
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 ..............................
For the years ended December 31,
2014
2013
2012
$ 16,663,685
(3,616,775)
(2,471,985)
(2,827,763)
7,747,162
(4,500,434)
$ 3,246,728
$ 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
In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2014,
2013 and 2012 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.
F-45
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
December 31, 2014, 2013 and 2012
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.
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:
For the years ended December 31,
2014
2013
2012
$ 2,322,204
$ 1,877,456
$ 1,400,859
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 ..............
(590,388)
(320,275)
1,340,022
(543,312)
(190,961)
1,166,481
(478,607)
(631,693)
1,287,952
145,740
(22,961)
92,135
6,100
—
305,325
(266,757)
235,583
$ 3,246,728
313,947
921
89,396
7,604
(239,148)
234,852
(259,991)
(135,041)
$ 2,322,204
194,921
(3,917)
137,510
25,041
—
176,996
(101,955)
(129,651)
$ 1,877,456
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-46
Laredo Petroleum, Inc.
Supplemental quarterly financial data
December 31, 2014 and 2013
Note 18—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 (loss) ...............................................................................
Net income (loss) per common share:
Year ended December 31, 2014
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$
173,310
$
183,044
$
200,241
$
237,290
60,038
(213)
64,561
(18,899)
69,164
83,407
32,623
201,278
Basic ................................................................................................
Diluted .............................................................................................
$
$
— $
— $
(0.13) $
(0.13) $
0.59
0.58
$
$
1.42
1.40
(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
F-47
(This page has been left blank intentionally.)
Corporate Information
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
Midstream &
Marketing
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.”
Laredo Petroleum, Inc.
15 W. Sixth Street, Suite 900
Tulsa, Oklahoma 74119
Office 918.513.4570
www.laredopetro.com