O N E
O N E
j o n e s e n e r g y + 2 0 1 3 a n n u a l r e p o r t
JONESJONESJONESONE 2 0 1 3
Acquires Sabine’s Anadarko
assets for $193.5 million
2 0 1 2
Acquires Chalker’s Cleveland
assets for $250 million
2 0 0 9
Acquires Crusader Energy Group
for $240.5 million
2 0 0 7
Sells Hansford Co. assets to
Laredo for $75 million
1 9 9 6
Jones Energy drills first horizontal
well in the Texas Panhandle
1 9 5 7
Jon Rex Jones joins his father
& brother in Albany
1 9 2 3
A.V. Jones begins work for
Marland Oil Company
2 0 1 3
IPO’s on the New York Stock
Exchange (NYSE: JONE)
2 0 1 1
JV with Southridge to enter the
Arkoma Woodford Play
2 0 0 8
Sells Shattuck Field to Noble for
$292 million ($66 million net)
2 0 0 1
Sells Hoover Field to Newfield
for $25 million
1 9 8 8
Jonny Jones & Jones family
form Jones Energy
1 9 3 2
Jones & Stasney form partnership
and move to Albany, Texas
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F A M I L Y
n e a r l y a c e n t u r y o f f a m i l y l e g a c y i n o i l a n d g a s
Our CEO, Jonny Jones, founded our predecessor company in 1988
in continuation of his family’s long history in the oil and gas business,
which dates back to the 1920’s. This picture shows Jonny’s grandfather,
A.V. Jones, on the right, and his partner H.R. Stasney. A few years after
forming a partnership in 1932, Jones and Stasney moved to Albany,
Texas to work the shallow zones in West Central Texas.
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T E A M
p e o p l e a r e t h e m o s t i m p o r t a n t f a c t o r i n o u r s u c c e s s
Although we are part of an industry that focuses on assets as
the differentiator, we look at things differently. We strive to create
a team-oriented environment that maintains the touch and feel of
a family business, like the one we started 25 years ago.
A letter from Jonny Jones
D E A R F E L L O W S H A R E H O L D E R S ,
Jones Energy is likely a very new
name to you. But in our family, oil
and gas has been running through
our veins for three generations.
The tradition that my grandfather
started in 1923, I chose to continue.
And in 1988, with an investment
of $3 million, I founded Jones as
a private E&P company. In 2013,
we took the logical next step and
entered the public market.
3
A letter from Jonny Jones
a v e r a g e d a i l y p r o d u c t i o n
( m b o e / d )
e b i t d a x
( $ i n m i l l i o n s )
p v - 1 0 o f p r o v e d r e s e r v e s
( $ i n m i l l i o n s )
18
16
14
12
10
8
6
4
2
0
28 % GROWTH
0
.
7
1
3
.
3
1
250
200
150
100
50
0
51 % GROWTH
0
.
5
0
2
7
.
5
3
1
1200
1000
800
600
400
200
0
30 % GROWTH
0
.
7
1
0
,
1
0
.
2
8
7
2012
2013
2012
2013
2012
2013
At Jones Energy, we create value by establishing
The pre-tax present value or “PV-10” of our total
a leadership position in the regions where we
proved reserves also increased by 30% to over
operate. We may not be the largest player, but
$1 billion. In December 2013, we completed our
our goal is to deliver the best returns. We only
$193.5 million acquisition of assets from Sabine
focus in areas where we can establish best-in-
Oil & Gas, increasing our core Cleveland acreage
class operations. In our main operating regions,
by over 40%. We spud our first well on the Sabine
the Cleveland formation in the Anadarko Basin
acreage just a matter of days after closing the
and the Woodford formation in the Arkoma Basin,
acquisition in December, and have integrated
we think we have accomplished that. We are
these assets into our 2014 development plan.
currently running 8 of our 10 rigs in the Cleveland
Finally, in 2013, we also entered into a new
and are generating very attractive returns,
partnership with Vanguard Natural Resources
comparing favorably to the best US shale plays.
to drill Woodford wells, and closed on our sixth
We see significant opportunity within our
agreement with BP in the Woodford.
existing footprint.
Our strategy continues to revolve around organic
and external growth. In 2013, we grew production
by 28% to 17.0 thousand barrels of oil equivalent
per day, and increased EBITDAX by over 50%.
4
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O N E
M I S S I O N
o u r m i s s i o n i s c l e a r
To be the premier Midcontinent E&P company, Jones Energy
is committed to utilizing its expertise to maximize value while
maintaining its culture of passion, integrity and focus.
2
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3
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P U R P O S E
o u r g r o w t h w i l l b e p u r p o s e f u l a n d d e l i b e r a t e
We make this commitment to you: Regardless of our expansion
plans, our growth will be purposeful and deliberate – grounded in
our strategy to only operate where we can be best in class.
A letter from Jonny Jones
“Since the company’s formation, Jones Energy
has strived to be the premier E&P company
in the US Midcontinent. As we enter our new
chapter as a public company, this remains
the foundation for all we do.”
In 2014, we will continue to execute our tactical
We started as a small family business over
plans within the Anadarko and Arkoma basins.
25 years ago. Even today, my family and our
We see the potential for the Tonkawa formation
management team own close to 30% of the
in the Anadarko Basin to provide upside opportu-
outstanding shares. But our goal remains the
nities along with additional scale in the Woodford
same: to create long-term value for our
formation. We will continue to evaluate acquisition
shareholders. We think we have a wonderful
opportunities within our existing footprint, but may
foundation to deliver on that proposition.
also pursue opportunities outside our core oper-
ating area. But we make this commitment to you:
Regardless of our expansion plans, our growth will
be purposeful and deliberate – grounded in our
strategy to only operate where we can be best in
We look forward to reporting our progress in
the coming years. Thank you for your support.
class. We will not overpay for assets. We will stay
Yours truly,
true to our tradition.
Since the company’s formation, Jones Energy
has strived to be the premier E&P company
in the US Midcontinent. As we enter our new
j o n n y j o n e s
chapter as a public company, this remains the
foundation for all we do.
Founder, Chairman & CEO
Jones Energy
7
T R A I L
F O U N D A T I O N
A T L A D Y
B I R D L A K E
JONES ENERGY
J U V E N I L E
D I A B E T E S
R E S E A R C H
F O U N D A T I O N
We are proud to be part of the small, but growing,
the issues in the community that matter most
oil and gas community in Austin, Texas. In fact,
to them. We look forward to continuing our local
Jones Energy has been based in Austin since
community efforts in 2014.
1993. Being an engaged and contributing member
of the Austin community is a responsibility that
we take seriously. The Trail Foundation at Lady
Bird Lake and the Juvenile Diabetes Research
Foundation are two aspects of the Austin
community that are dear to our hearts. In 2013,
our employees took a day to get their hands
dirty and help make Lady Bird Lake, one of the
true crown jewels of the Austin community,
even more beautiful. The impact we make on
the Austin community does not end with what
we do as an organization. We also encourage
our employees to take time to be involved in
“ w o r k h a r d , p l a y h a r d ” – this is an attitude
we embrace at Jones. It fits Austin; a young, fit
city that is constantly on the move. And it fits Jones.
On day one, each Austin-based employee gets
a complimentary gym membership. We encourage
lunchtime workouts; we encourage physical
activity of all kinds. We know fit employees with
healthy lifestyles translate into better attitudes,
better productivity and an energized workplace.
In the end, what is good for our employees is
good for Jones Energy. i t h e l p s u s w i n i n
e v e r y w a y , t o g e t h e r .
8
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C U L T U R E
w o r k h a r d , p l a y h a r d
This is an attitude we embrace at Jones Energy. We encourage
physical activity of all kinds, and make it a priority to do our part for
the Austin community. It helps us win in every way, together.
2
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A
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O N E
F O C U S
2,542
T O T A L D R I L L I N g
L O C A T I O N S
115,076
N E T A C R E S
17,014
B O E / D D A I L Y
p R O D U C T I O N
O U R R E L E N T L E S S F O C U S O N E x E C U T I O N H A S B E E N K E Y
Focus is a word we use a lot at Jones Energy. It is a principle
that companies can often lose sight of. We consider our focus on one
area, the Midcontinent, for the past 25 years to be a
competitive advantage in itself.
A N A D A R K O B A S I N
Key Formation: Cleveland
Drilling Locations: 1,731
Cleveland 4Q13 Daily Production:
10.8 MBoe/d
A R K O M A B A S I N
Key Formation: Woodford
Drilling Locations: 811
Woodford 4Q13 Daily Production:
4.1 MBoe/d
A U S T I N O F F I C E
Jones Energy has been operating in one area,
the US Midcontinent, for over 25 years. Since our
founding, we have drilled over 500 horizontal wells
in nine target formations in the Midcontinent. In fact,
18 years ago we drilled our first horizontal well in
the Brown Dolomite formation. Today, we are
focused on two core areas in the US Midcontinent,
the Cleveland formation within the Anadarko Basin,
and the Woodford formation within the Arkoma
Basin. In 2004, we drilled our first horizontal well in
the Cleveland formation, which remains one of
our core operating areas today. Since then, Jones
Energy has drilled over 340 horizontal wells in
the Cleveland, representing approximately 20%
of all horizontal wells drilled in the formation,
more than any other operator.
The ‘stacked pay’ nature of the Midcontinent has
been a huge factor in our success over the past
25 years. We see substantial opportunity within
the Cleveland and Woodford formations, but also
see potential upside stemming from the Tonkawa
and Marmaton formations. In fact, we plan to drill
three Tonkawa test wells in 2014. We are excited
about the opportunities within our existing asset
base, and will continue to execute on our organic
growth plans in 2014. We will remain open-minded
when looking for opportunities to supplement
our organic growth with acquisitions, but promise
to be prudent when considering potential M&A.
We will not to forget the success we have achieved
over the past 25 years from focusing on the
US Midcontinent.
1 1
JonES EnErgy, InC.
Consolidated Statements of Operations
(In thousands of dollars)
Operating revenues
oil and gas sales
other revenues
Total operating revenues
Operating costs and expenses
Lease operating
Production taxes
Exploration
Depletion, depreciation and amortization
Impairment of oil and gas properties
Accretion of discount
general and administrative (including non-cash
compensation expense)
Total operating expenses
operating income
Other income (expense)
Interest expense
net gain (loss) on commodity derivatives
gain on bargain purchase
gain (loss) on sales of assets
other income (expense), net
Income (loss) before income tax
Income tax provision
Current
Deferred
Total income tax provision
net income (loss)
net income attributable to non-controlling interests
net income (loss) attributable to controlling interests
Adjusted net income (1)
EBITDAX (2)
Production (MMBoe)
Proved reserves (MMBoe)
year Ended December 31,
2013
2012
$ 258,063 $148,967
847
259,169 149,814
1,106
27,781
12,865
1,710
114,136
14,415
608
23,097
5,583
356
80,709
18,821
533
31,902
15,875
203,417 144,974
4,840
55,752
(30,774) (25,292)
16,684
-
1,162
(7,446)
(2,606)
(2,566)
-
(78)
(33,418)
22,334
85
(156)
(71)
22,405
24,591
$ (2,186) $
-
473
473
(3,079)
-
(3,079)
$ 54,792 $ 29,411
$ 204,997 $ 135,741
6.2
89.0
4.9
85.3
(1) Adjusted net income is a supplemental non-GAAP financial measure that is used by management and external users of the
Company’s consolidated financial statements. We define adjusted net income as net income excluding the impact of certain
non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas
properties, non-cash compensation expense, and the gain on bargain purchase associated with the Southridge acquisition
in 2011. For a reconciliation of adjusted net income to our net income, see Item 6. “Selected Financial Data –Non-GAAP
financial measures” in our attached Form 10-K.
(2) EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s
consolidated financial statements. We define EBITDAX as earnings before interest expense, income taxes, depreciation,
depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of
matured derivative contracts, and other items. For a reconciliation of EBITDAX to our net income, see Item 6. “Selected
Financial Data –Non-GAAP financial measures” in our attached Form 10-K.
f o r m
10-K
j o n e s e n e r g y
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(cid:1) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
FORM 10-K
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2013
(cid:2) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number: 001-36006
Jones Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
80-0907968
(I.R.S. Employer
Identification No.)
807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(Address of principal executive offices) (Zip Code)
Tel: (512) 328-2953
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of class
Name of each exchange on which registered
Class A Common Stock, $0.001 par value
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Exchange 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 (cid:2) No (cid:1)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes (cid:2) No (cid:1)
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 (cid:1) No (cid:2)
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 during the preceding
12 months (or for such shorter period that the registrant was required to submit and post such files). Yes (cid:1) No (cid:2)
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. (cid:1)
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.
Large accelerated filer (cid:2)
Accelerated filer (cid:2)
Smaller reporting company (cid:2)
Non-accelerated filer (cid:1)
(Do not check if a
smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes (cid:2) No (cid:1)
As of June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, there was no
public market for the registrant’s common stock. The registrant’s common stock began trading on the New York Stock
Exchange on July 24, 2013. The aggregate market value of the voting and non-voting common stock held by non-affiliates of
the registrant computed as of December 31, 2013 based on the closing price of the Class A common stock on the New York
Stock Exchange on December 31, 2013 of $14.48 per share was $161.7 million.
There were 12,526,580 and 36,836,333 shares of the registrant’s Class A and Class B common stock, respectively,
outstanding on March 5, 2014.
Portions of the registrant’s definitive proxy statement for the 2014 Annual Meeting of Stockholders, to be filed no later
than 120 days after the end of the fiscal year, which we refer to as the Proxy Statement, are incorporated by reference into
Part III of this Annual Report on Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
Cautionary Statement Regarding Forward-Looking Statements
The information in this Annual Report on Form 10-K (the ‘‘Annual Report’’), includes ‘‘forward-
looking statements.’’ All statements, other than statements of historical fact included in this report,
regarding our strategy, future operations, financial position, estimated revenues and losses, projected
costs, prospects, plans and objectives of management are forward-looking statements. The words
‘‘could,’’ ‘‘should,’’ ‘‘believe,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘project’’ and similar
expressions are intended to identify forward-looking statements, although not all forward-looking
statements contain such identifying words. These forward-looking statements are based on our current
expectations and assumptions about future events and are based on currently available information as
to the outcome and timing of future events. When considering forward-looking statements, you should
keep in mind the risk factors and other cautionary statements described under the heading ‘‘Risk
Factors’’ included in this report. These forward-looking statements are based on management’s current
belief, based on currently available information, as to the outcome and timing of future events, actions
and developments including:
(cid:127) business strategy;
(cid:127) estimated current and future net reserves and present value thereof;
(cid:127) drilling and completion of wells including our identified drilling locations;
(cid:127) cash flows and liquidity;
(cid:127) financial strategy, budget, projections and operating results;
(cid:127) oil, natural gas and NGLs realized prices;
(cid:127) customers’ elections to reject ethane and include it as part of the natural gas stream;
(cid:127) timing and amount of future production of oil and natural gas;
(cid:127) availability and cost of drilling and production equipment;
(cid:127) availability and cost of oilfield labor;
(cid:127) the amount, nature and timing of capital expenditures, including future development costs;
(cid:127) ability to fund our 2014 capital expenditure budget;
(cid:127) availability and terms of capital;
(cid:127) development results from our identified drilling locations;
(cid:127) ability to generate returns and pursue opportunities;
(cid:127) marketing of oil, natural gas and NGLs;
(cid:127) property acquisitions;
(cid:127) costs of developing our properties and conducting other operations;
(cid:127) general economic conditions and the commodity price environment;
(cid:127) effectiveness and extent of our risk management activities;
(cid:127) estimates of future potential impairments;
(cid:127) environmental liabilities;
(cid:127) counterparty credit risk;
(cid:127) governmental regulation and taxation of the oil and natural gas industry;
2
(cid:127) developments in oil-producing and natural gas-producing countries;
(cid:127) uncertainty regarding our future operating results;
(cid:127) technology; and
(cid:127) plans, objectives, expectations and intentions contained in this report that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and
uncertainties, most of which are difficult to predict and many of which are beyond our control, incident
to the exploration for and development and production of oil and natural gas. These risks include, but
are not limited to, commodity price volatility, inflation, lack of availability of drilling and production
equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the
uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of
production, cash flow and access to capital, the timing of development expenditures, and the other risks
described under ‘‘Risk Factors’’ in this report.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas
that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality
of available data, the interpretation of such data and price and cost assumptions made by reservoir
engineers. In addition, the results of drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve estimates may differ significantly
from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this report occur, or should
underlying assumptions prove incorrect, our actual results and plans could differ materially from those
expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this report are expressly qualified
in their entirety by this cautionary statement. This cautionary statement should also be considered in
connection with any subsequent written or oral forward-looking statements that we or persons acting on
our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-
looking statements, all of which are expressly qualified by the statements in this section, to reflect
events or circumstances after the date of this report.
References
Unless indicated otherwise in this Annual Report or the context requires otherwise, all references
to ‘‘Jones Energy,’’ the ‘‘Company,’’ ‘‘our company,’’ ‘‘we,’’ ‘‘our’’ and ‘‘us’’ refer to Jones Energy, Inc.
and its subsidiaries, including Jones Energy Holdings, LLC (‘‘JEH LLC’’). Jones Energy, Inc. (‘‘JONE’’)
is a holding company whose sole material asset is an equity interest in JEH LLC.
3
Item 1. Business
Organization
PART 1
Jones Energy, Inc. was incorporated pursuant to the laws of the State of Delaware in March 2013
to become a holding company for JEH LLC. As the sole managing member of JEH LLC, Jones
Energy, Inc. is responsible for all operational, management and administrative decisions relating to
JEH LLC’s business and consolidates the financial results of JEH LLC and its subsidiaries. Pursuant to
the terms of a corporate reorganization that was completed in connection with the closing of Jones
Energy, Inc.’s initial public offering (‘‘IPO’’) on July 29, 2013, the pre-IPO owners of JEH LLC
converted their existing membership interests in JEH LLC into JEH LLC Units and amended the
existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH LLC
Units and to admit Jones Energy, Inc. as the sole managing member of JEH LLC.
Jones Energy, Inc.’s certificate of incorporation authorizes two classes of common stock, Class A
common stock and Class B common stock. Only Class A common stock was offered to investors
pursuant to the IPO. The Class B common stock is held by the pre-IPO owners of JEH LLC and can
be exchanged (together with a corresponding number of JEH LLC Units) for shares of Class A
common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits,
stock dividends and reclassifications and other similar transactions. Our Class A common stock has
been listed on the New York Stock Exchange (‘‘NYSE’’) since July 2013.
Overview
We are an independent oil and gas company engaged in the exploration, development, production
and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and
Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in
continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We
have grown rapidly by leveraging our focus on low cost drilling and completions methods and our
horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have
accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins,
having concentrated our operations in the Anadarko basin for 25 years and applied our knowledge to
the Arkoma basin since 2011. We have drilled over 645 total wells, including over 460 horizontal wells,
since our formation and delivered compelling rates of return over various commodity price cycles. Our
operations are focused on horizontal drilling and completions within two distinct basins in the Texas
Panhandle and Oklahoma:
(cid:127) the Anadarko Basin—targeting the liquids-rich Cleveland, Granite Wash, Tonkawa and
Marmaton formations; and
(cid:127) the Arkoma Basin—targeting the Woodford shale formation.
We optimize returns through a disciplined emphasis on controlling costs and promoting operational
efficiencies, and we believe we are recognized as one of the lowest-cost drilling and completion
operators in the Cleveland and Woodford shale formations.
The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil
and natural gas basins in the United States, enjoying multiple producing horizons and extensive well
control demonstrated over seven decades of development. The formations we target are generally
characterized by oil and liquids-rich natural gas content, extensive production histories, long-lived
reserves, high drilling success rates and attractive initial production rates. We focus on formations in
our operating areas that we believe offer significant development and acquisition opportunities and to
which we can apply our technical experience and operational excellence to increase proved reserves and
4
production to deliver attractive economic rates of return. Our goal is to build value through a
disciplined balance between developing our current inventory of 2,542 gross identified drilling locations
and other opportunities within our existing asset base, and actively pursuing joint venture agreements,
farm-out agreements, joint operating agreements and similar partnering agreements, which we refer to
as joint development agreements, organic leasing and strategic acquisitions. In all of our joint
development agreements, we control the drilling and completion of a well, which is the phase during
which we can leverage our operational expertise and cost discipline. Following completion, we in some
cases may turn over operatorship to a partner during the production phase of a well. We believe the
ceding to us of drilling and completion operatorship in our areas of operation by several large oil and
gas companies, including ExxonMobil and BP, reflects their acknowledgement of our low-cost, safe and
efficient operations.
As of December 31, 2013, our total estimated proved reserves were 89.0 MMBoe, of which 56%
were classified as proved developed reserves. Approximately 19% of our total estimated proved
reserves as of December 31, 2013 consisted of oil, 37% consisted of NGLs, and 44% consisted of
natural gas. As of December 31, 2013, our properties included 835 gross producing wells. For the three
years ended December 31, 2013, we drilled 218 wells, substantially all of which we drilled as operator.
The following table presents summary reserve, acreage and production data for each of our core
operating areas:
As of December 31, 2013
Estimated Net
Proved Reserves
Acreage
Year Ended
December 31, 2013
Average Daily Net
Production
MMBoe
% Oil and
NGLs(1)
Gross
Acreage
Net
Acreage MBoe/d
% Oil and
NGLs(1)
Anadarko basin:
Cleveland . . . . . . . . . . . . . . . . . . . . . . .
Granite Wash . . . . . . . . . . . . . . . . . . . .
Arkoma basin:
Woodford . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties . . . . . . . . . . . . . . . . . . . .
57.5
2.4
26.2
2.9
89.0
62.3% 152,983
39.0% 14,361
91,376
6,595
46.3% 14,584
24.2% 36,609
3,839
13,266
10.0
1.1
4.0
1.9
55.7% 218,537
115,076
17.0
66.0%
45.5%
30.3%
34.5%
52.8%
(1) Ethane is an NGL and is included in this percentage. Due to declines in ethane pricing and
increases in natural gas prices, beginning in December 2012, purchasers of our Woodford
production have been electing not to recover ethane from the natural gas stream and instead have
been paying us based on the natural gas price for the ethane left in the gas stream. As a result of
the increased energy content associated with the returned ethane and the absence of plant
shrinkage, this ethane rejection has increased the incremental revenue and volumes that we receive
for our natural gas production relative to what we would have received if the ethane was
separately recovered, but has reduced physical barrels of liquid ethane that we are selling.
5
The following table presents summary well and drilling location data for each of our key
formations for the date indicated:
Anadarko basin:
As of December 31, 2013
Producing
Wells
Identified
Drilling
Locations(1)
Gross
Net
Gross
Net
667
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granite Wash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Tonkawa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 209
Marmaton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 371
424
20
283
14
Arkoma basin:
Woodford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
127
264
835
49
69
811
451
415
2,542
888
425
16
123
209
98
17
(1) Our total identified drilling locations include 366 gross locations associated with proved
undeveloped reserves as of December 31, 2013. We have estimated our drilling locations
based on well spacing assumptions for the areas in which we operate and other criteria.
See ‘‘Business—Development of Proved Undeveloped Reserves’’ and ‘‘Business—Drilling
Locations’’ for more information regarding our proved undeveloped reserves and the
processes and criteria through which these drilling locations were identified.
Our 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled
97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million,
$310 million of which we expect will be used to drill and complete wells. The remainder of the 2014
capital expenditure budget is devoted to leasing and other discretionary expenditures. Please see
‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Liquidity and Capital Resources.’’ Assuming current market conditions and drilling success rates
comparable to our historical performance, we believe we will be able to fund all of our 2014 budgeted
capital expenditures with our cash flow from operations and projected availability under our senior
secured revolving credit facility.
We currently have ten rigs running in our two core areas, eight in the Cleveland and two in the
Woodford. We currently expect to allocate our 2014 capital expenditure budget as follows:
2014 Capital
Expenditure
Budget
(in millions)
Drilling and completion:
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Woodford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties and activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$250
50
10
20
20
$350
6
Our Business Strategies
Our goal is to increase value by leveraging the operational expertise of our management and
technical teams in our operating areas in order to achieve compelling economic returns and attractive
reserve, production and cash flow growth. We seek to achieve this goal by executing the following
strategies:
Grow Production and Reserves through Development of Our Multi-Year Inventory.
We intend to focus on development activities in our operating areas, which we believe to be
repeatable, low-risk and low-cost, in order to grow our current level of production and proved reserves.
We have extensive experience in the Anadarko and Arkoma basins, having drilled over 645 wells in the
area since 1988. We believe our historical drilling experience, together with the results of substantial
industry activity within our operating areas, helps reduce the risk and uncertainty associated with
drilling horizontal wells in these areas. As of December 31, 2013, we have identified 2,542 gross drilling
locations, which we believe will enable us to drill and develop our resource base over many years. We
expect 100% of our development capital expenditures in 2014 to be dedicated to horizontal drilling.
Leverage Our Extensive Operational Expertise to Continually Reduce Costs and Enhance Returns.
Decades of experience in the Midcontinent region and emphasis on operational execution and cost
control have allowed us to drill and complete wells at significantly lower cost than most other operators
and, as a result, to realize compelling economic returns. For example in the Cleveland, over the past
seven years, we have been able to reduce our well spud-to-release time, which directly affects drilling
costs, from approximately 30 days to approximately 26 days. We seek to apply this expertise in other
projects within our areas of operation to enhance their economic profile.
Execute Strategic Acquisitions, Joint Development Agreements, and Organic Leasing Where Our Operating
Experience Can Be Leveraged.
We have successfully increased our production and reserves through selective acquisitions, targeted
joint development agreements and organic leasing, and we intend to continue to evaluate acquisition,
partnering and leasing opportunities in and around our areas of operation. We pursue joint
development opportunities that complement our acquisition strategy by providing a capital efficient and
risk-lowering approach to securing and developing acreage and drilling locations that allows us to apply
our expertise in the drilling and completion phase. In this regard, we have established long-term
agreements with several large exploration and production companies such as BP, ConocoPhillips, Devon
Energy, ExxonMobil, Linn Energy, Vanguard Natural Resources and Samson, in which they have
farmed-out portions of their basin operations to us. We have drilled over 279 wells in connection with
these types of agreements, over 157 of which have been drilled in connection with an active 13-year
drilling relationship with ExxonMobil. We also continue to seek new leasing opportunities to expand
our acreage position and complement our existing drilling inventory, as we believe that targeted organic
leasing around our existing acreage provides the ability for greater returns due to cost and operating
synergies in overlapping areas of operation.
Focus on Exploiting Additional Upside Potential Within Our Portfolio.
We plan to continue exploiting our proved reserves to maximize production through various
enhanced recovery methods, such as optimizing frack design and number of stages. Furthermore, the
stacked reservoirs within our asset base provide exposure to additional upside potential in several
emerging resource plays. Recently, offset operators have been pursuing the exploration of two newly-
identified resource opportunities, the Tonkawa and Marmaton formations in the Anadarko basin. We
have begun to assess the potential of these formations within our asset base and believe, based on
7
these results, we have approximately 580 potential drilling locations in the Tonkawa and Marmaton
formations that provide us with additional resource potential. We plan to start to test the potential of
the Tonkawa formation by drilling three pilot wells on our acreage in 2014. Further, our current
leasehold position provides longer term potential exposure to other prospective formations found in the
Anadarko basin, including the Douglas, Cottage Grove, Cherokee Shale, Atoka Shale, Upper, Middle
and Lower Morrow formations, and other prospective formations found in the Arkoma basin, including
the Hartshorne, Spiro, Wapanuka, Cromwell and Caney Shale formations.
Maintain Operational Control Over Our Drilling and Completion Operations.
We operated substantially all of the wells that we drilled and completed during 2013, allowing us
to effectively manage the timing and levels of our development spending, overall well costs and
operating costs. In addition, we expect to operate the drilling and completion phase on approximately
71% of our 2,542 gross identified drilling locations. With over 78% of our acreage held by existing
production, we also will not be required to expend significant capital to hold acreage in our portfolio.
We believe that continuing to exercise a high degree of control over our acreage position will provide
us with flexibility to manage our drilling program and optimize our returns and profitability.
Opportunistically Allocate Our Resources and Capital to Enhance Returns.
Our drilling inventory comprises oil, natural gas and NGLs, which enables us to adjust our
development approach based on prevailing commodity prices. Currently, we intend to capitalize on the
more favorable liquids pricing environment by continuing to drill acreage with significant oil and NGL
components, where 100% of our 2014 drilling capital budget is focused. Within our existing portfolio,
oil and NGLs account for approximately 56% of our proved reserves as of December 31, 2013. In
addition, we expect that continuing to operate the substantial majority of our drilling locations will
allow us to reallocate our capital and resources opportunistically in response to market conditions. Our
disciplined focus on well-level returns in allocating our capital and resources has been a key component
of our ability to deliver successful results through various commodity price cycles over the last 25 years.
Competitive Strengths
We possess a number of competitive strengths that we believe will allow us to successfully execute
our business strategy:
Geographic Focus in the Prolific U.S. Midcontinent.
Our operations are focused in the Midcontinent region, targeting liquids-rich opportunities in the
Anadarko and Arkoma basins of Texas and Oklahoma. We generally focus on formations characterized
by oil and liquids-rich natural gas content, extensive production histories, long-lived reserves, high
drilling success rates, and attractive initial production rates. Furthermore, our areas of operation are
proximate to well-developed natural gas and liquids midstream infrastructure and oilfield services
providers, which we believe reduces the risk of production delays and facilitates adequate takeaway
capacity. 100% of our 2014 drilling capital budget is devoted to the Anadarko and Arkoma basins in
the U.S. Midcontinent.
Multi-Year Drilling Inventory in Existing and Emerging Resource Plays.
Our drilling inventory consists of approximately 2,542 gross identified drilling locations in the
Anadarko and Arkoma basins, and our development plans target locations that we believe are low-cost,
provide attractive economics, present a low risk and support a relatively predictable production profile.
As of December 31, 2013, we had identified 667 gross drilling locations in the Cleveland play, 811 gross
drilling locations in the Arkoma Woodford shale formation and 209 gross locations in the Tonkawa
8
formation. Our concentrated leasehold position has been delineated largely through drilling on our
Cleveland leasehold, which we expanded substantially through our Chalker and Sabine acquisitions. We
have also expanded through joint development agreements with large independent producers and major
oil and gas companies in the Cleveland and Woodford formations. In 2013, we drilled 97 gross wells, as
compared to 48 gross wells drilled in 2012, representing a 102% increase. Furthermore, we have
identified additional locations in several emerging resource plays that we intend to explore and develop
in the coming years, including 33 gross locations in the Granite Wash formation, 209 gross locations in
the Tonkawa formation and 371 gross locations in the Marmaton formation.
Extensive Operational Expertise and Low-Cost Operating Structure.
Drilling horizontal wells has been our primary drilling approach for the last nine years. Having
drilled over 460 horizontal wells in nine formations in our areas of operation since 1996, we have
established systematic protocols that we believe provide repeatable results. We also have established
relationships with oilfield service providers, vendors and crews, allowing for continued cost efficiencies.
As an example, we have consistently drilled horizontal Cleveland wells at a meaningfully lower cost
than most of our competition in the same area. Through our focus on drilling, completion and
operational efficiencies, we are able to effectively control costs and deliver attractive rates of return
and profitability.
Strong Financial Position and Conservative Policies.
We are committed to maintaining a conservative financial profile in order to preserve operational
flexibility and financial stability. We believe that our operating cash flow, together with projected
availability under our senior secured revolving credit facility, provide us with the financial flexibility to
pursue acquisitions, joint development agreements and organic leasing opportunities. In addition, we
intend to actively hedge our future production in order to reduce the impact of commodity price
volatility on our cash flows. Each quarter, we typically review the production results from recently
drilled wells and begin entering into commodity price hedges of up to 100% of expected production
from those wells in order to secure our rates of return for up to five years. As of December 31, 2013,
we had over $680 million of notional value in existing hedges with the lenders under our credit
facilities.
High Caliber Management Team with Deep Operating Experience and a Proven Track Record.
The top four executives of our management team average more than 25 years of industry
experience. Furthermore, our management team averages over 20 years of industry experience and has
worked together developing assets for many years, resulting in a high degree of continuity. We have
assembled a strong technical staff of geoscientists, field operations managers and engineers with
significant experience drilling horizontal wells and with fracture stimulation of unconventional
formations, which has resulted in a successful track record of reserve and production growth. In
addition, our management team has extensive expertise and operational experience in the oil and
natural gas industry with a proven track record of successfully negotiating, executing and integrating
acquisitions. Members of our management team have previously held positions with major and large
independent oil and natural gas companies, including ExxonMobil, BP, Southwestern Energy, Samson,
Marathon and Standard Oil.
Alignment of Management Team.
Our predecessor was founded in 1988 by our CEO, Jonny Jones, in continuation of his family’s
history in the oil and gas business, which dates back to the 1920’s. Jones family members and our
management team currently control approximately 28% of our combined voting power and economic
9
interest. We believe the equity interests of our officers and directors align their interests and provide
substantial incentive to grow the value of our business.
Our Operations
Our areas of operations
We own leasehold interests in oil and natural gas producing properties, as well as in undeveloped
acreage, substantially all of which are located in the Anadarko and Arkoma basins in Texas and
Oklahoma. The majority of our interests are in producing properties located in fields characterized by
what we believe to be long-lived, predictable production profiles and repeatable development
opportunities.
For a discussion of the risks inherent in oil and natural gas production, please read ‘‘Risk
Factors—Drilling for and producing oil, natural gas and NGLs are high risk activities with many
uncertainties that could adversely affect our business, financial condition or results of operations.’’
Anadarko basin
Approximately 67% of our estimated proved reserves as of December 31, 2013 and approximately
66% of our average daily net production for the year ended December 31, 2013 were located in the
Anadarko basin. The Anadarko basin is one of the most prolific oil and natural gas producing basins in
the United States, covering approximately 50,000 square miles primarily in Oklahoma, but also
including the upper Texas Panhandle, southwestern Kansas, and southeastern Colorado.
Our wells in this area produce oil, natural gas and NGLs from various formations at depths from
approximately 7,000 feet to 12,000 feet. We drilled 73 gross (56 net) wells as operator in the Anadarko
basin in 2013. Our operations in the Anadarko basin are primarily focused on the Cleveland formation
where we have 424 producing wells. We also have acreage in the Granite Wash, Tonkawa, Marmaton,
Atoka shale and Cherokee shale formations located in the eastern portion of the Texas Panhandle and
western Oklahoma. We intend to explore and develop the Tonkawa formation beginning in 2014, and
believe that the Marmaton, Atoka shale and Cherokee shale formations provide longer-term potential
in the Anadarko basin.
On December 18, 2013, we acquired from Sabine Mid-Continent, LLC certain producing and
undeveloped oil and gas assets in the Anadarko basin located in the Texas Panhandle and western
Oklahoma for approximately $193.5 million, subject to customary closing adjustments. The acquired
Sabine properties produced approximately 2,227 boe/day in the 14 day period in 2013 during which we
owned the properties.
Producing Formations. Our production in the Anadarko basin is currently derived primarily from
the following formations, where we have 444 gross (297 net) producing wells and where we have
identified 700 gross (441 net) drilling locations as of December 31, 2013, of which 238 have proved
undeveloped reserves attributed to them as of December 31, 2013. See ‘‘Drilling Locations’’ for more
information regarding the processes and criteria through which these drilling locations were identified.
(cid:127) Cleveland Formation. Our Cleveland acreage is located in Ochiltree, Lipscomb and Hemphill
counties in Texas and Ellis county in Oklahoma. The Cleveland formation ranges from depths of
approximately 7,000 feet to 8,800 feet and is characterized by a tight, shaly sand with low
permeability that lends itself to improved recovery through enhanced drilling and completion
techniques.
As of December 31, 2013, we operated 322 gross (244 net) producing wells with working
interests ranging from approximately 25% to 100% for our leasehold in the Cleveland formation.
Our Cleveland properties contained 57.5 MMBoe of estimated net proved reserves as of
10
December 31, 2013, 62% of which are oil and NGLs, and generated an average daily net
production of 10.9 MBoe/d for the month ended December 31, 2013. We have identified
667 gross (425 net) drilling locations in the Cleveland formation as of December 31, 2013. Of
these 667 locations, 523 locations (78%) are attributable to acreage that is currently held by
production and 232 locations (35%) are attributable to proved undeveloped reserves as of
December 31, 2013. We are currently running 8 rigs in the Cleveland formation and plan to
spend approximately $250 million drilling and completing wells there in 2014, representing
approximately 81% of our drilling and completion budget.
(cid:127) Granite Wash Formation. Our Granite Wash acreage is located in Roberts, Hemphill and
Wheeler counties in Texas and Roger Mills, Beckham, Custer and Washita counties in
Oklahoma. The Granite Wash spans multiple zones from depths of approximately 9,000 feet to
12,000 feet and is composed of tight, complex, quartz rich alluvial liquids-rich wash.
As of December 31, 2013, we operated 19 gross (13 net) producing wells in this formation with
an average working interest of 75%. Our Granite Wash properties contained 2.4 MMBoe of
estimated net proved reserves as of December 31, 2013, approximately 39% of which are oil and
NGLs. We have not allocated any capital expenditures to the Granite Wash formation in our
2014 drilling budget. We have 33 gross (16 net) remaining drilling locations in the Granite Wash
formation as of December 31, 2013.
Additional Targeted Formations. We also own properties in the following formations of the
Anadarko basin, where we have identified 580 gross (332 net) drilling locations as of December 31,
2013, none of which have proved reserves attributed to them. See ‘‘Drilling Locations’’ for more
information regarding the processes and criteria through which these drilling locations were identified.
(cid:127) Tonkawa Formation. As of December 31, 2013, we have identified 209 gross (123 net) drilling
locations in the Tonkawa formation in Lipscomb and Hemphill counties in Texas. In addition, we
have other properties in the Tonkawa formation located in Ellis and Roger Mills counties in
Oklahoma. The Tonkawa is a newly-targeted horizontal oil formation at depths of approximately
6,000 feet to 8,000 feet and is characterized by fine to very fine-grained sandstone, ranging in
thickness from 20 feet to 40 feet. We drilled our first horizontal Tonkawa well in May of 2010
and drilled two additional horizontal wells in the formation under a farm-out with Samson that
is not part of our current leasehold. Beginning in the second quarter of 2014, we plan to drill
three additional test wells in different areas of the Company’s leasehold acreage in the Tonkawa
formation.
(cid:127) Marmaton Formation. As of December 31, 2013, we have identified 371 gross (209 net) drilling
locations in the Marmaton formation. Our properties in the Marmaton formation are all
undeveloped and span three sub-formations: properties located in Ellis County, Oklahoma
characterized by fluvio-deltaic sands, properties located in Northeast Ochiltree and Northwest
Lipscomb counties, Texas characterized by shallow marine sands, and properties located in
Ochiltree county, Texas characterized by algal reef complex. The Marmaton sand is a tight, shaly
sand with similar reservoir characteristics to the Cleveland. The Marmaton sand ranges in
thickness from 40 feet to 80 feet while the reef ranges from 80 feet to 150 feet. We have not
allocated any capital expenditures to the Marmaton formation in our 2014 drilling budget.
Future Potential Opportunities. Our current leasehold position provides longer term potential
exposure to other prospective formations in the Anadarko basin, including the Atoka, Cherokee,
Douglas, Cottage Grove, Upper, Middle and Lower Morrow formations. As of December 31, 2013, the
acreage associated with these opportunities is approximately 82% held by production. The Atoka and
Cherokee formations, in particular, have attractive geologic properties, and we may elect to pursue
their development in the future.
11
Arkoma Basin
Approximately 29% of our estimated proved reserves as of December 31, 2013, and approximately
19% of our average daily net production for December 2013, were located in the Arkoma basin. The
Arkoma basin is a historically prolific, largely gas-prone basin extending from eastern Oklahoma into
western Arkansas. The basin produces natural gas from multiple horizons, which range in depth from
500 to 21,000 feet.
As of December 31, 2013, we operated approximately 66% of our properties in the Arkoma basin
and produce primarily from the Woodford formation. Our current leasehold position also provides
longer term potential exposure to other prospective formations in the Arkoma basin, including the
Hartshorne, Spiro, Wapanuka, Cromwell and Caney formations.
(cid:127) Woodford Shale Formation. Our properties in the Woodford shale formation are located in Atoka,
Coal, Pittsburg and Hughes counties in eastern Oklahoma. The Woodford shale formation
ranges from depths of approximately 5,000 feet to 12,700 feet and is composed of 75 to 220 foot
thick black siliceous shale in our operating area. The Woodford shale in this area is prospective
for natural gas with a high concentration of associated NGLs.
As of December 31, 2013, we operated 84 gross (44 net) producing wells in the formation with
an average working interest of 52%. Our Woodford shale formation properties contained
26.2 MMBoe of estimated net proved reserves as of December 31, 2013, 46% of which are
NGLs, and generated an average daily net production of 3.3 MBoe/d for the month ended
December 31, 2013. We drilled 13 gross (4 net) additional wells in the Woodford shale
formation in 2013. We have identified 811 gross (98 net) drilling locations in the Woodford shale
formation as of December 31, 2013, of which 13% have proved undeveloped reserves attributed
to them as of December 31, 2013. We plan to spend approximately $50 million drilling and
completing wells there in 2014, representing approximately 16% of our budgeted 2014 drilling
capital expenditures.
Drilling Locations
We have identified a total of 2,542 gross (888 net) drilling locations, all of which are horizontal
drilling locations. Of these 2,542 locations, 2,033 locations are attributable to acreage that is currently
held by production and approximately 366 (14%) are attributable to proved undeveloped reserves as of
December 31, 2013. In order to identify drilling locations, we apply geologic screening criteria based on
the presence of a minimum threshold of gross pay sand thickness in a section and then consider the
number of sections and the appropriate well density to develop the applicable field. In making these
assessments, we include properties in which we hold operated and non-operated interests, as well as
redevelopment opportunities. Once we have identified acreage that is prospective for the targeted
formations, well placement is determined primarily by the regulatory spacing rules prescribed by the
governing body in each of our operating areas. Wells drilled in the Cleveland formation adhere to
128-acre spacing (5 wells per section) while wells in the Woodford shale formation are developed on
80-acre and 120-acre spacing, depending on the area. Wells drilled in the Granite Wash formation were
developed on 128-acre or 213-acre spacing. Wells drilled in the Tonkawa and Marmaton formations
adhere to 160-acre spacing. We view the risk profiles for the Tonkawa and Marmaton formations as
being higher than for our other drilling locations due to relatively less available production data and
drilling history.
Our identified drilling locations are scheduled to be drilled over many years. The ultimate timing
of the drilling of these locations will be influenced by multiple factors, including oil, natural gas and
NGL prices, the availability and cost of capital, drilling and production costs, the availability of drilling
services and equipment, drilling results, lease expirations, gathering systems, processing, marketing and
pipeline transportation constraints, regulatory approvals and other factors. In addition, a number of our
12
identified drilling locations are associated with joint development agreements, and if we do not meet
our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to
continue to develop certain acreage covered by that agreement. For a discussion of the risks associated
with our drilling program, see ‘‘Risk Factors—Our identified drilling locations are scheduled to be
drilled 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 or delay associated
expected production. In addition, we may not be able to raise the amount of capital that would be
necessary to drill a substantial portion of our identified drilling locations.’’
Estimated Proved Reserves
The following table sets forth summary data with respect to our estimated net proved oil, natural
gas and NGLs reserves as of December 31, 2013, 2012 and 2011, which are based upon reserve reports
of Cawley, Gillespie & Associates, Inc., or Cawley Gillespie, our independent reserve engineers. Cawley
Gillespie’s reports were prepared consistent with the rules and regulations of the SEC regarding oil and
natural gas reserve reporting in effect during such periods. The summary data with respect to our
estimated net proved oil and natural gas reserves as of December 31, 2013 include the reserves
attributable to the properties acquired in the Sabine acquisition.
Reserve Data:
Estimated proved reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
Total estimated proved reserves (MBoe)(1) . . . . .
Estimated proved developed reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
Total estimated proved developed reserves
As of December 31,
2013
2012
2011
16,688
236,648
32,915
89,045
7,129
139,622
19,101
12,540
228,080
34,746
85,299
4,261
110,956
16,320
7,440
244,579
34,606
82,809
2,535
110,434
14,021
(MBoe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
49,501
39,074
34,961
Estimated proved undeveloped reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
Total estimated proved undeveloped reserves
9,559
97,025
13,814
8,278
117,124
18,426
4,905
134,146
20,586
(MBoe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
PV-10 (in millions)(2) . . . . . . . . . . . . . . . . . . . . . .
Standardized measure (in millions)(3) . . . . . . . . . .
$
39,544
1,017
941
$
46,225
782
782
$
47,849
916
916
(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an
approximate energy equivalency. This is a physical correlation and does not reflect a value
or price relationship between the commodities.
(2) PV-10 is a non-GAAP financial measure and generally differs from Standardized
Measure, the most directly comparable GAAP financial measure, because it does not
include the effect of income taxes on discounted future net cash flows. Neither PV-10 nor
Standardized Measure represents an estimate of the fair market value of our oil and
natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the
relative size and value of proved reserves held by companies without regard to the
13
specific tax characteristics of such entities. See ‘‘Reconciliation of PV-10 to Standardized
Measure’’ below.
(3) Standardized measure is calculated in accordance with Statement of Financial Accounting
Standards No. 69 Disclosures About Oil and Gas Producing Activities, as codified in ASC
Topic 932, Extractive Activities—Oil and Gas. Prior to the reorganization that occurred in
2013 in connection with the IPO of shares of its Class A common stock, the predecessor
of Jones Energy, Inc. was a limited liability company that was not subject to entity-level
taxation during the periods presented except for the Texas franchise tax. Accordingly,
standardized measure for historical periods was not reduced for income taxes. However,
upon consummation of the IPO, Jones Energy, Inc. became subject to entity-level
taxation, which is reflected in the standardized measure as of December 31, 2013.
The following table sets forth the benchmark prices used to determine our estimated proved
reserves for the periods indicated.
As of December 31,
2013
2012
2011
Oil, Natural Gas and NGLs Benchmark Prices:
Oil (per Bbl)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (per MMBtu)(2) . . . . . . . . . . . . . . . . . . . .
NGLs (per Bbl)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . .
$96.78
3.67
28.33
$94.71
2.76
31.27
$96.19
4.12
47.26
(1) Benchmark prices for oil reflect the unweighted arithmetic average first-day-of-the-month
prices for the prior 12 months using WTI Cushing posted prices. These prices were
utilized in the reserve reports prepared by Cawley Gillespie and in management’s internal
estimates and are adjusted by well for content, quality, transportation fees, geographical
differentials, marketing bonuses or deductions and other factors affecting the price
received at the wellhead. As of December 31, 2013, 2012 and 2011, the average realized
prices for oil were $91.74, $90.74 and $92.04 per Bbl, respectively.
(2) Benchmark prices for natural gas in the table above reflect the unweighted arithmetic
average first-day-of-the-month prices for the prior 12 months, respectively, using Henry
Hub prices. These prices were utilized in the reserve reports prepared by Cawley
Gillespie and in management’s internal estimates and are adjusted by well for content,
quality, transportation fees, geographical differentials, marketing bonuses or deductions
and other factors affecting the price received at the wellhead. As of December 31, 2013,
2012 and 2011, the average realized prices for natural gas were $3.13, $2.24 and $3.83 per
MMBtu, respectively.
(3) Prices for NGLs in the table above reflect the average realized prices for the prior
12 months. Benchmark prices for NGLs vary depending on the composition of the NGL
basket and current prices for the various components thereof, such as butane, ethane, and
propane, among others. Due to declines in ethane prices relative to natural gas prices,
beginning in 2012, purchasers of our Woodford production have been electing not to
recover ethane from the natural gas stream and instead are paying us based on the
natural gas price for the ethane left in the gas stream. As a result of the increased energy
content associated with the returned ethane and the absence of plant shrinkage, this
ethane rejection has increased the incremental revenue and volumes that we receive for
our natural gas product relative to what we would have received if the ethane was
separately recovered, but has reduced physical barrels of liquid ethane that we are selling.
14
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the
most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized
Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized
Measure of discounted future net cash flows at the applicable date, before deducting future income
taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to
investors because it presents the discounted future net cash flows attributable to our estimated net
proved reserves prior to taking into account future corporate income taxes, and it is a useful measure
for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors
may utilize the measure as a basis for comparison of the relative size and value of our reserves to other
companies. We use this measure when assessing the potential return on investment related to our oil
and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of
discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted
future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of PV-10 to the Standardized Measure of discounted
future net cash flows at December 31, 2013, 2012 and 2011.
PV-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of future income taxes discounted at 10% . . . .
As of December 31,
2013
2012
2011
(in millions)
$782
—
$1,017
76
$916
—
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 941
$782
$916
Prior to the IPO, the Company was not subject to federal income tax; hence no income taxes were
applied to reserve values in the previous years.
Internal Controls
Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by
our corporate reservoir engineering staff, all of whom are independent from our operating teams. We
maintain internal evaluations of our reserves in a secure reserve engineering database. The corporate
reservoir engineering staff interacts with our internal petroleum engineers and geoscience professionals
in each of our operating areas and with operating, accounting and marketing employees to obtain the
necessary data for the reserves estimation process. Reserves are reviewed and approved internally by
our senior management team on a semi-annual basis. We anticipate that the audit committee of our
board of directors will conduct a similar review on an annual basis. We expect to have our reserve
estimates evaluated by Cawley Gillespie, our independent third party reserve engineers, or another
independent reserve engineering firm, at least annually.
Our internal professional staff works closely with Cawley Gillespie, to ensure the integrity, accuracy
and timeliness of data that is furnished to them for their reserve estimation process. We provide all of
the reserve information maintained in our secure reserve engineering database to the external
engineers, as well as other pertinent data, such as geologic maps, well logs, production tests, material
balance calculations, well performance data, operating procedures and relevant economic criteria. We
make all requested information, as well as our pertinent personnel, available to the external engineers
as part of their evaluation of our reserves. Various procedures are used to ensure the accuracy of the
data provided to our independent petroleum engineers, including review processes. Changes in reserves
from the previous report are closely monitored. Reconciliation of reserves from the previous report,
which includes an explanation of all significant changes, is reviewed by both the engineering
15
department and upper management, including our chief operating officer. Our independent petroleum
engineers prepare our annual reserves estimates, whereas interim estimates are internally prepared.
Technology Used to Establish Proved Reserves
Under 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 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 Cawley Gillespie 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, electrical logs, radioactivity logs, core analyses,
geologic maps and available downhole and production data, seismic data and well test data. Reserves
attributable to producing wells with sufficient production history were estimated using appropriate
decline curves or other performance relationships. Reserves attributable to producing wells with limited
production history and for undeveloped locations were estimated using 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 Responsible Technical Persons
Internal engineer. Eric Niccum, our Executive Vice President and Chief Operating Officer, is the
technical person primarily responsible for overseeing the preparation of our reserves estimates.
Mr. Niccum is also responsible for liaising with and oversight of our third party reserve engineer.
Mr. Niccum is a graduate of Purdue University with a Bachelor of Science degree in Mechanical
Engineering. He has 20 years of energy experience.
Cawley Gillespie. Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm
(F-693), made up of independent registered professional engineers and geologists. The firm has
provided petroleum consulting services to the oil and gas industry for over 50 years. No director,
officer, or key employee of Cawley Gillespie has any financial ownership in us or any of our affiliates.
Cawley Gillespie’s compensation for the required investigations and preparation of its report is not
contingent upon the results obtained and reported, and Cawley Gillespie has not performed other work
for us that would affect its objectivity. The engineering audit presented in the Cawley Gillespie report
was supervised by W. Todd Brooker, Senior Vice President at Cawley Gillespie. Mr. Brooker is an
experienced reservoir engineer having been a practicing petroleum engineer since 1989. He has more
than 23 years of experience in reserves evaluation and joined Cawley Gillespie as a reserve engineer in
1992. He has a Bachelors of Science Degree in Petroleum Engineering from the University of Texas at
Austin and is a Registered Professional Engineer in the State of Texas (License No. 83462).
16
Development of Proved Undeveloped Reserves
As of December 31, 2013, none of our proved undeveloped reserves at December 31, 2013 were
scheduled to be developed on a date more than five years from the date the reserves were initially
booked as proved undeveloped. However, certain of our proved undeveloped reserves are associated
with joint development agreements with third parties that include obligations to drill a specified
minimum number of wells in a time frame that is shorter than five years. If we do not meet our
obligation to drill the minimum number of wells specified in a joint development agreement, we will
lose the right to continue to develop the undeveloped acreage covered by the agreement, which in
some cases would result in a reduction in our proved undeveloped reserves. Historically, our drilling
and development programs were substantially funded from our cash flow from operations. Our
expectation is to continue to fund our drilling and development programs primarily from our cash flow
from operations and projected availability under our senior secured revolving credit facility. Based on
our current expectations of our cash flows and drilling and development programs, which include
drilling of proved undeveloped locations, we believe that we can fund the drilling of our current
inventory of proved undeveloped locations and our expansion activities in the next five years from our
cash flow from operations and, if needed, borrowings under our senior secured revolving credit facility.
For a more detailed discussion of our liquidity position, please read ‘‘Management’s discussion and
analysis of financial condition and results of operations—Liquidity and capital resources.’’
Our proved undeveloped reserves have decreased from 46.2 MMBoe at December 31, 2012 to
39.5 MMBoe at December 31, 2013 due to (i) the conversion of 5.1 MMBoe of proved undeveloped
reserves to proved developed reserves; (ii) net negative revisions of 18.1 MMBoe, primarily due to the
expiration of the Company’s JDA with Southridge (15.5 MMBoe) and production performance in the
Cleveland (3.5 MMBoe); (iii) additions of 8.9 MMBoe from extensions and discoveries; and
(iv) additions of 7.6 MMBoe for purchases of minerals in place. Proved undeveloped reserves declined
as a percentage of total reserves from 54% for the year ending December 31, 2012 to 44% for the year
ending December 31, 2013. For the year ended December 31, 2013, we converted 5.1 MMBoe of
proved undeveloped reserves to proved developed reserves or 11% of total proved undeveloped
reserves booked at December 31, 2012. We incurred approximately $104 million in capital to convert
proved undeveloped reserves to proved developed reserves during the year ended December 31, 2013.
Our 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled
97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million,
$310 million of which we expect to use to drill and complete wells. Costs of proved undeveloped
reserve development in 2013 do not represent the total costs of these conversions, as additional costs
may have been recorded in previous years. Estimated future development costs relating to the
development of 2013 year-end proved undeveloped reserves is $533 million.
17
Operating Data
The following table sets forth summary data regarding production volumes, average prices and
average production costs associated with our sale of oil and natural gas for the periods indicated.
Year Ended December 31,
2013
2012
2011
Production and Operating Data:
Net Production Volumes(1):
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total (MBoe) . . . . . . . . . . . . . . . . . . . . . . . . .
1,557
17,575
1,724
6,210
746
14,066
1,773
4,863
811
11,443
1,215
3,933
Average net production (Boe/d) . . . . . . . . . . . .
17,014
13,287
10,775
Average Sales Price(2):
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (per Mcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . .
Combined (per Boe) realized . . . . . . . . . . . . . . . .
Average Unit Costs per Boe:
Lease operating expense . . . . . . . . . . . . . . . . . . .
Production tax expense . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . .
General and administrative expense(3) . . . . . . . . .
$ 93.22
3.16
33.30
41.56
$
4.47
2.07
18.38
5.14
$ 89.71
2.17
29.07
30.63
$
4.75
1.15
16.60
3.26
$ 90.96
3.49
44.04
42.53
$
5.48
1.36
17.52
4.24
(1) The Lipscomb SE field constituted approximately 26% of our estimated proved reserves
as of December 31, 2013. Our production from the Lipscomb SE field was 1,751 MBoe
and 36 MBoe for the years ended December 31, 2013 and 2012, respectively. The 2013
production was comprised of 858 MBbls of oil, 2,786 MMcf of natural gas and 430 MBbls
of NGLs. The 2012 production was comprised of 17 MBbls of oil, 61 MMcf of natural gas
and 9 MBbls of NGLs. The Lipscomb SE field was acquired in December 2012, therefore
we had no production from the field for the year ended December 31, 2011.
The Coalgate Woodford field constituted approximately 19% of our estimated proved
reserves as of December 31, 2013. Our production from the Coalgate Woodford field was
1,158 MBoe, 1,529 MBoe, and 675 MBoe for the years ended December 31, 2013, 2012
and 2011, respectively. The 2013 production was comprised of 19 MBbls of oil,
4,766 MMcf of natural gas and 345 MBbls of NGLs. The 2012 production was comprised
of 33 MBbls of oil, 4,357 MMcf of natural gas and 770 MBbls of NGLs. The 2011
production was comprised of 10 MBbls of oil, 2,029 MMcf of natural gas and 327 MBbls
NGLs.
(2) Prices do not include the effects of derivative cash settlements.
(3) General and administrative includes non-cash stock-based compensation of $13.6 million,
$0.6 million and $1.1 million for the years ended December 31, 2013, 2012 and 2011,
respectively. Excluding stock-based compensation from the above metric results in average
general and administrative cost per Boe of $2.95, $3.15 and $3.95 for the years ended
December 31, 2013, 2012 and 2011, respectively.
18
Drilling Activity
The following table sets forth information with respect to wells drilled and completed during the
periods indicated. The information should not be considered indicative of future performance, nor
should a correlation be assumed between the number of productive wells drilled, quantities of reserves
found or economic value.
Development Wells:
Year Ended December 31,
2013
2012
2011
Gross
Net Gross
Net Gross
Net
22
34
71
Productive . . . . . . . . . . . . . . . . . . . . . . . . .
61
Mechanical failure . . . . . . . . . . . . . . . . . . . — —
1 — —
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
44
2
97
Exploratory Wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
1
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —
2
2
1
Total Wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . . .
61
Mechanical failure . . . . . . . . . . . . . . . . . . . — —
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —
97
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . .
97
61
44
2
2
48
22
34
71
1 — —
1
2
1
24
73
34
For the three years ended December 31, 2013, we had no developmental wells that were deemed
dry wells and 4 gross (2 net) exploratory wells deemed dry wells. In this same period, we experienced a
total of 2 mechanical failures that were not reservoir related. As of December 31, 2013, there were
32 gross (20 net) development wells in the process of drilling or completion. For the three years ended
December 31, 2013, we drilled 191 gross (115 net) wells as operator with over a 99% success rate.
From January 1, 2013 through December 31, 2013, we successfully drilled 38 gross proved
undeveloped wells and completed 29 gross proved undeveloped wells.
Productive Wells
The following table sets forth our total gross and net productive wells by oil or natural gas
completion as of December 31, 2013.
Operated(1) . . . . . . . . . . . . . . . . . . . . . . . .
Non-operated . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
Natural Gas
Total
Gross
Net
Gross
Net
Gross
Net
175
57
232
137
14
151
312
291
603
233
31
264
487
348
835
370
45
415
(1) Includes wells on which we act as contract operator.
Gross wells are the total number of producing wells in which we own an interest, and net wells are
the sum of our fractional working interests owned in gross wells.
Acreage Data
The following table sets forth certain information regarding the developed and undeveloped
acreage in which we have an interest as of December 31, 2013 for each of our producing areas.
19
Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
Acreage that is prospective for the Tonkawa, Marmaton and other formations is included in these totals
as these formations overlie one another throughout much of our acreage. As of December 31, 2013,
over 78% of our leasehold acreage was held by existing production.
Developed Acres
Undeveloped Acres
Total
Gross
Net
Gross
Net
Gross
Net
Cleveland . . . . . . . . . . . . .
Woodford(1) . . . . . . . . . . .
Granite Wash . . . . . . . . . .
Other . . . . . . . . . . . . . . . .
119,007
8,889
14,361
21,610
73,408
2,533
6,595
7,534
33,976
5,695
—
14,999
17,968
1,306
152,983
14,584
— 14,361
36,609
5,732
91,376
3,839
6,595
13,266
All properties(2) . . . . . . .
163,867
90,070
54,670
25,006
218,537
115,076
(1) Excludes gross and net acreage associated with the joint development agreements with
Vanguard. Acreage associated with the Vanguard joint development agreement is assigned
to us at the time the first well in each unit is pooled and/or drilled.
(2) Includes proved undeveloped reserves associated with joint development agreements with
third parties. If we do not meet our obligation to drill the minimum number of wells
specified in a joint development agreement, we will lose the right to continue to develop
the undeveloped acreage covered by the agreement, which would result in the loss of any
proved undeveloped reserves attributable to such undeveloped acreage. Please see ‘‘Risk
Factors—If we do not fulfill our obligation to drill the minimum number of wells
specified in our joint development agreements, we will lose the right to develop the
undeveloped acreage associated with the agreement and any proved undeveloped reserves
attributable to such undeveloped acreage.’’
Undeveloped acreage expirations
The following table sets forth the number of gross and net undeveloped acres as of December 31,
2013 that will expire over the next three years by operating area unless production is established within
the spacing units covering the acreage prior to the expiration dates or unless the existing leases are
renewed prior to expiration.
Expiring 2014
Expiring 2015
Expiring 2016
Gross
Net
Gross
Net
Gross
Net
Cleveland . . . . . . . . . . . . . . . . . . . . .
Woodford . . . . . . . . . . . . . . . . . . . . .
Granite Wash . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . .
6,048
2,517
—
142
2,766
299
—
27
5,545
3,506
—
—
3,585
4,232
566
662
—
—
— 854
2,442
164
—
437
All properties . . . . . . . . . . . . . . . .
8,707
3,092
9,051
4,894
5,005
3,043
A majority of the leases comprising the acreage set forth in the table above will expire at the end
of their respective primary terms unless production from the acreage has been established prior to such
date, in which event the lease will remain in effect until the cessation of production in commercial
quantities. We also have options to extend some of our leases through payment of additional lease
bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt
to secure a new lease upon the expiration of certain of our acreage; however, there may be third party
leases that become effective immediately if our leases expire at the end of their respective terms and
production has not been established prior to such date. We do not have any of our proved undeveloped
reserves as of December 31, 2013 attributed to acreage whose lease expiration date precedes the
20
scheduled initial drilling date. Our leases are mainly fee leases with primary terms of three to five
years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to
both primary term and royalty interests.
Competition
The oil and natural gas industry is highly competitive. We compete with numerous entities,
including major domestic and foreign oil companies, other independent oil and natural gas concerns
and individual producers and operators. Many of these competitors are large, well-established
companies and have financial and other resources substantially greater than ours. As a result, our
competitors may be able to pay more for productive oil and natural gas properties and exploratory
prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than
our financial or personnel resources permit. Our ability to acquire additional properties and to find and
develop reserves will depend on our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. Please read ‘‘Risk Factors—We may be
unable to compete effectively with larger companies, which may adversely affect our ability to generate
sufficient revenues.’’
We are also affected by competition for drilling rigs, equipment, services, supplies and qualified
personnel. In recent years, the United States onshore oil and natural gas industry has experienced
shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed
development drilling and other exploration activities and caused significant increases in the prices for
this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how
they would affect our development and exploitation programs.
Segment Information and Geographic Areas
The Company operates in one industry segment, which is the exploration, development and
production of oil and natural gas, and all of its operations are conducted in one geographic area of the
United States.
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 20% to 25%. Our net revenue interests average 57% for our operated leases and 35% including
all operated and non-operated leases.
Over 78% of our leases (based on net acreage) are held by production and do not require lease
rental payments.
Marketing and Major Customers
Our oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated
purchasers based on published price bulletins reflecting an established field posting price. As a
consequence, the prices we receive for oil and liquids move up and down in direct correlation with the
oil market as it reacts to supply and demand factors. We do not own any oil or liquids pipelines or
other assets for the transportation of those commodities, and transportation costs related to moving oil
are deducted from the price received for oil.
Our natural gas is sold under both long-term and short-term natural gas purchase agreements.
Natural gas produced by us is sold at various delivery points at or near producing wells to natural gas
gathering and marketing companies. We receive proceeds from prices that are based on various
21
pipeline indices less any associated fees. For approximately 98% of our natural gas production, we are
paid for the extracted NGLs based on a negotiated percentage of the proceeds that are generated from
the customer’s sale of the liquids, or based on other negotiated pricing arrangements. We do not own
any natural gas pipelines or other assets for the transportation of natural gas.
Recently, changes in NGL prices have altered market conditions. Due primarily to the large supply
of ethane on the market, the price of ethane has dropped significantly over the last year. For a
discussion of the effect of recent changes in NGL prices, see ‘‘Management’s Discussion and Analysis
of Financial Condition and Results of Operations—Outlook.’’
During the year ended December 31, 2013, the largest purchasers were PVR Midstream,
Unimark LLC, Mercuria, Valero, and Plains Marketing, which accounted for approximately 15%, 13%,
13%, 13% and 6% of consolidated oil and gas sales, respectively. If we were to lose any one of our
customers, the loss could temporarily delay production and sale of our oil and natural gas in the
related producing region. If we were to lose any single customer, we believe we could identify a
substitute customer to purchase the impacted production volumes. However, if one or more of our
larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a
detrimental effect on our production volumes in general and on our ability to find substitute customers
to purchase our production volumes. For a discussion of the risks associated with the loss of key
customers, please read ‘‘Risk factors—Our customer base is concentrated, and the loss of any one of
our key customers could, therefore, adversely affect our financial condition and results of operations.’’
Seasonality
Generally, but not always, the demand for natural gas decreases during the summer months and
increases during the winter months, resulting in seasonal fluctuations in the price we receive for our
natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this
fluctuation.
Title to Properties
Prior to completing an acquisition of producing oil and natural gas properties, we perform title
reviews on significant leases, and depending on the materiality of properties, we may obtain a title
opinion or review previously obtained title opinions. As a result, title examinations have been obtained
on a significant portion of our properties.
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of
the titles to our properties on which we do not have proved reserves. Prior to the commencement of
drilling operations on those properties, we conduct a thorough title examination and perform curative
work with respect to significant defects. To the extent title opinions or other investigations reflect title
defects on those properties, we are typically responsible for curing any title defects at our expense. We
generally will not commence drilling operations on a property until we have cured any material title
defects on such property.
We conduct a portion of our operations through joint development agreements with third parties.
Certain of our joint development agreements include drill-to-earn arrangements, whereby we are
assigned title to properties from the third party after we complete wells and, in the case of certain
counterparties, after completion reports relating to the wells have been approved by regulatory
authorities, whose approval may be delayed. Furthermore, certain of our joint development agreements
specify that assignments are only to occur when the wells are capable of producing hydrocarbons in
paying quantities. These additional conditions to assignment of title may from time to time apply to
wells of substantial value.
22
We believe that we have satisfactory title to all of our material assets. Although title to these
properties is subject to encumbrances in some cases, such as customary interests generally retained in
connection with the acquisition of real property, customary royalty interests and contract terms and
restrictions, liens under operating agreements, liens related to environmental liabilities associated with
historical operations, liens for current taxes and other burdens, easements, restrictions and minor
encumbrances customary in the oil and natural gas industry, we believe that none of these liens,
restrictions, easements, burdens and encumbrances will materially detract from the value of these
properties or from our interest in these properties or materially interfere with our use of these
properties in the operation of our business. In addition, we believe that we have obtained sufficient
rights-of-way grants and permits from public authorities and private parties for us to operate our
business in all material respects as described in this Annual Report on Form 10-K.
Regulations
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. All of the jurisdictions in which we own or operate
producing oil and natural gas properties have 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 unitization or pooling of 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. The effect of these regulations is to limit the amount of oil
and natural gas that we can produce from our wells and limit the number of wells or locations at which
we can drill, although we can apply for exceptions to such regulations or to have reductions in well
spacing. Moreover, each state generally imposes a production or severance tax with respect to the
production and sale of oil, natural gas and NGLs within its jurisdiction.
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.
Although we believe we are in substantial compliance with all applicable laws and regulations, such
laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the
future costs or impact of compliance. Additional proposals and proceedings that affect the oil and
natural gas industry are regularly considered by Congress and federal agencies, the states, and the
courts. We cannot predict when or whether any such proposals may become effective. Our competitors
in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that
affect our operations.
Environmental Matters and Regulation
Our operations are subject to stringent and complex federal, state and local laws and regulations
that govern the protection of the environment, as well as the discharge of materials into the
environment. These laws and regulations may, among other things:
(cid:127) require the acquisition of various permits before drilling commences;
(cid:127) require the installation of pollution control equipment in connection with operations;
(cid:127) restrict or prohibit our drilling and production activities during periods when such activities
might affect wildlife;
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(cid:127) place restrictions or regulations upon the types, quantities or concentrations of materials or
substances used in our operations;
(cid:127) restrict the types, quantities or concentrations of various substances that can be released into the
environment or used in connection with drilling, production and transportation activities;
(cid:127) limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected
areas; and
(cid:127) require remedial measures to mitigate pollution from former and ongoing operations, such as
site restoration, pit closure and plugging of abandoned wells.
These laws, rules and regulations may also restrict the rate of oil and natural gas production below
the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry
increases the cost of doing business in the industry and consequently affects profitability. Additionally,
federal, state and local lawmakers and agencies frequently revise environmental laws and regulations,
and such changes could result in increased costs for environmental compliance, such as waste handling,
permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our
operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our
business operations are subject.
Solid and Hazardous Waste Handling and Releases
The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes
regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and
non-hazardous waste. Drilling fluids, produced waters, and most of the other wastes associated with the
exploration, development, production and transportation of oil and gas are currently excluded from
regulation as hazardous wastes under RCRA. In the course of our operations, however, we generate
some industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as
hazardous wastes. Although a substantial amount of the waste generated in our operations are
regulated as non-hazardous solid waste rather than hazardous waste, there is no guarantee that the
EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous
waste. Moreover, it is possible that certain oil and gas exploration and production wastes now classified
as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in
an increase in our costs to manage and dispose of waste, which could have a material adverse effect on
our results of operations and financial position.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also
known as ‘‘Superfund,’’ and comparable state laws and regulations impose liability without regard to
fault or legality of the original conduct, on certain classes of persons with respect to the release into
the environment of substances designated under CERCLA as hazardous substances. These classes of
persons, or so-called potentially responsible parties, or PRPs, include the current and past owners or
operators of a site where the release occurred and anyone who disposed or arranged for the disposal of
a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and
several, strict 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 U.S. Environmental Protection Agency, or the EPA, and, in some
instances, third parties to take actions in response to threats to public health or the environment and to
seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more
stringent state statutes. In addition, it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
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Although CERCLA generally exempts ‘‘petroleum’’ from the definition of hazardous substance, in
the course of our operations, we have generated and will generate wastes that may fall within
CERCLA’s definition of hazardous substances and may have disposed of these wastes at disposal sites
owned and operated by others. We may also be the owner or operator of sites on which hazardous
substances have been released. To our knowledge, neither we nor our predecessors have been
designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or
operators of our properties that are named as PRPs related to their ownership or operation of such
properties. In the event contamination is discovered at a site on which we are or have been an owner
or operator or to which we sent hazardous substances, we could be liable for the costs of investigation
and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that have been used for oil and natural
gas exploration and production for many years. Although we believe we have utilized operating and
waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or
hydrocarbons may have been released on or under the properties owned or leased by us, or on or
under other locations, including offsite locations, where such substances have been taken for disposal.
In addition, some of these properties have been operated by third parties or by previous owners or
operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not
under our control. These properties and the substances disposed or released on them may be subject to
the RCRA, CERCLA, and analogous state laws. Spills or other contamination required to be
remediated has not required material capital expenditures to date. In the future, we could be required
to remediate property, including groundwater, containing or impacted by previously disposed wastes
(including wastes disposed or released by prior owners or operators, or property contamination,
including groundwater contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future or mitigate existing contamination.
Clean Water Act
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws
impose restrictions and strict controls with respect to the discharge of pollutants, including spills and
leaks of produced water and other oil and natural gas wastes, into waters of the United States, a term
broadly defined. The discharge of pollutants into regulated waters is prohibited, except in accordance
with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also
prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless
authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties, as well as require remedial or
mitigation measures, for non-compliance with discharge permits or other requirements of the Clean
Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of
wastes, we may be liable for penalties and costs. The EPA has announced its intention to propose
regulations by 2014 under the Clean Water Act to develop standards for wastewater discharges from
hydraulic fracturing and other natural gas production activities.
Safe Drinking Water Act
The SDWA regulates, among other things, underground injection operations. Congress has
considered legislation which, if successful, would impose additional regulation under the SDWA upon
the use of hydraulic fracturing fluids. If enacted, such legislation could impose on our hydraulic
fracturing operations permit and financial assurance requirements, requirements that we adhere to
construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet
plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing
to the SDWA regulatory and permitting requirements, the proposed legislation would require the
disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties
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opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals
used in the process could adversely affect ground water. In addition, the EPA has taken the position
that hydraulic fracturing with fluids containing diesel fuel is subject to the Underground Injection
Control program in states in which EPA is the permitting authority and released permitting guidance
on the use of diesel fuel as an additive in hydraulic fracturing fluids in February 2014. The EPA has
also commenced a study of the potential adverse effects that hydraulic fracturing may have on water
quality and public health, and a committee of the U.S. House of Representatives has commenced its
own investigation into hydraulic fracturing practices. The Department of Energy, at the direction of the
President, also studied hydraulic fracturing and provided broad recommendations regarding best
practices and other steps to enhance companies’ safety and environmental performance of hydraulic
fracturing. If the pending or similar legislation is enacted or other new requirements or restrictions
regarding hydraulic fracturing are adopted as a result of these studies, we could incur substantial
compliance costs and the requirements could negatively impact our ability to conduct fracturing
activities on our assets.
Other Regulation of Hydraulic Fracturing
On November 23, 2011, the EPA announced that it was granting in part a petition to initiate
rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used
in oil and gas exploration and production. Also, BLM is considering proposed rules regarding well
stimulation, chemical disclosures, and other requirements for hydraulic fracturing on federal and Indian
lands. BLM released a proposed rule requiring the disclosure of chemicals used during hydraulic
fracturing and addressing drilling plans, water management, and wastewater disposal on federal and
Indian lands in May 2012. However, BLM pulled back its proposal in January 2013 after reviewing
comments and published an updated proposed rule on May 24, 2013. President Obama created the
Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13,
2012, which is charged with coordinating and aligning federal agency research and scientific studies on
unconventional natural gas and oil resources.
Hydraulic fracturing is also subject to regulation at the state and local levels. Several states have
proposed or adopted legislative or administrative rules regulating hydraulic fracturing operations. For
example, the Railroad Commission of Texas, implementing a state law passed in June 2011, adopted
the Hydraulic Fracturing Chemical Disclosure Rule on December 13, 2011. The rule requires public
disclosure of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after
February 1, 2012. Additionally, Texas has authorized the Texas Commission on Environmental Quality
to suspend water use rights for oil and gas users in the event of serious drought conditions and has
imposed more stringent emissions, monitoring, inspection, maintenance, and repair requirements on
Barnett Shale operators to minimize Volatile Organic Compound, or VOC, releases. Other states that
we operate in, including Louisiana and Oklahoma, have adopted similar chemical disclosure measures.
Please see ‘‘Risk Factors—Federal and state legislative and regulatory initiatives relating to hydraulic
fracturing and other oil and gas production activities as well as governmental reviews of such activities
could result in increased costs, additional operating restrictions or delays, which could adversely affect
our production’’ for a further discussion of state hydraulic fracturing regulation. In addition to state
laws, 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.
Oil Pollution Act
The primary federal law related to oil spill liability is the Oil Pollution Act, or the OPA, which
amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and
liabilities on certain ‘‘responsible parties’’ related to the prevention of oil spills and damages resulting
from such spills in or threatening United States waters or adjoining shorelines. For example, operators
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of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct
annual spill training for certain employees and provide varying degrees of financial assurance. A liable
‘‘responsible party’’ includes the owner or operator of a facility, vessel or pipeline that is a source of an
oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the
lessee or permittee of the area in which a discharging facility is located. OPA assigns strict joint and
several liability, without regard to fault, to each liable party for oil removal costs and a variety of public
and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the
event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.
Air Emissions
Our operations may be subject to the Clean Air Act, or CAA, and comparable state and local
requirements for the control of emissions from sources of air pollution. Federal and state laws require
new and modified sources of air pollutants to obtain permits prior to commencing construction. Major
sources of air pollutants are subject to more stringent, federally imposed requirements including
additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might
require installation of additional controls. Administrative enforcement actions for failure to comply
strictly with air pollution regulations or permits are generally resolved by payment of monetary fines
and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for
civil penalties or injunctions or require us to forego construction, modification or operation of certain
air emission sources.
We may incur expenditures in the future for air pollution control equipment in connection with
obtaining or maintaining operating permits and approvals for air emissions. For instance, on April 17,
2012, the EPA released final rules that establish new air emission controls for oil and natural gas
production and natural gas processing operations. The rules became effective on October 15, 2012.
Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions
of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address
hazardous air pollutants frequently associated with oil and natural gas production and processing
activities. The rules establish specific requirements regarding emissions from compressors, dehydrators,
storage tanks and other production equipment in addition to leak detection requirements for natural
gas processing plants. In October 2012, several challenges to the EPA’s rules were filed by various
parties, including environmental groups and industry associations. In a January 16, 2013 unopposed
motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the
rules. The case remains in abeyance. EPA issued a final rule revising certain aspects of the rules on
August 5, 2013 and has indicated that it may reconsider other aspects of the rules. Depending on the
outcome of such judicial proceedings and regulatory actions, the rules may be further modified or
rescinded or the EPA may issue new rules. Additionally, on December 11, 2012, seven states submitted
a notice of intent to sue the EPA to compel the agency to make a determination as to whether
standards of performance limiting methane emissions from oil and gas sources are appropriate, and, if
so, to promulgate performance standards for methane emissions from the oil and gas sector, which was
not addressed in the EPA rules that became effective on October 15, 2012. The notice of intent also
requested the EPA issue emission guidelines for the control of methane emissions from existing oil and
gas sources. These rules that took effect on October 15, 2012, as well as any modifications to these
rules or additional rules, could require a number of modifications to our operations including the
installation of new equipment.
Endangered Species and Migratory Birds
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened
species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered,
restrictions may be imposed on activities adversely affecting that species or its habitat. Similar
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protections are offered to migratory birds under the Migratory Bird Treaty Act. Criminal liability can
attach for even an incidental taking of migratory birds, and the federal government recently issued
indictments under the Migratory Bird Treaty Act to several oil and gas companies after dead migratory
birds were found near reserve pits associated with drilling activities.
We conduct operations in areas where certain species that are listed as threatened or endangered
under the ESA may be present. For example, our operations in Oklahoma overlap with the range of
the American Burying Beetle, which is listed as endangered. The presence of endangered or threatened
species may force us to modify or terminate our operations in certain areas. Additionally, the
designation of previously unidentified endangered or threatened species could cause us to incur
additional costs or become subject to operating restrictions or bans or limit future development activity
in the affected areas. For example, the U.S. Fish and Wildlife Service proposed on December 11, 2012,
to list the Lesser Prairie Chicken as a threatened species under the Endangered Species Act. The
period for the public to submit comments on this proposal initially was set to expire on March 11, 2013
but, in response to requests submitted by federal congressmen, the Fish and Wildlife Service reopened
the comment period on May 6, 2013. A final decision regarding whether to finalize the proposal is
expected by March 30, 2014. The listing of the Lesser Prairie Chicken, or any other species in areas
that we operate, could force us to incur additional costs and delay or otherwise limit our operations.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands may be subject to the
National Environmental Policy Act, or NEPA, which requires federal agencies, including the
Department of Interior, to evaluate major agency actions having the potential to significantly impact
the environment. In the course of such evaluations, an agency will prepare an Environmental
Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project
and, if necessary, will prepare a more detailed Environmental Impact Statement that may be 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 process has the potential to delay or impose
additional conditions upon the development of oil and natural gas projects.
Climate Change
More stringent laws and regulations relating to climate change and greenhouse gases, or GHGs,
may be adopted in the future and could cause us to incur material expenses in complying with them.
Both houses of Congress have actively considered legislation to reduce emissions of GHGs, but no
legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission
control, the EPA has begun to regulate GHGs as pollutants under the CAA. The EPA has adopted
regulations affecting emissions of GHGs from motor vehicles and is also requiring permit review for
GHGs from certain stationary sources that emit GHGs at levels above statutory and regulatory
thresholds. In June 2010, the EPA adopted the Prevention of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule, which sets regulatory emissions thresholds for stationary sources of
GHGs under the Prevention of Significant Deterioration (PSD) and Title V programs. PSD permitting
has been applicable to new and modified stationary sources that emit GHGs above statutory and
regulatory thresholds since January 2, 2011. The EPA has announced its intent to consider lowering the
Tailoring Rule regulatory thresholds, which would likely subject additional stationary sources to GHG
permitting requirements under the PSD and Title V programs. We do not believe our operations are
currently subject to these permitting requirements, but if our operations become subject to these or
other similar requirements, we could incur significant costs to control our emissions and comply with
regulatory requirements.
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In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes
reporting and monitoring requirements on various types of facilities and industries. On November 9,
2010, the EPA issued final rules to expand its existing GHG reporting rule to include onshore oil and
natural gas production, processing, transmission, storage, and distribution facilities. Reporting was first
required in 2012 for emissions occurring in 2011. Our operations are not currently subject to this
program, but there is no guarantee that the EPA will not expand the program to additional sources and
facilities. Should we be required to report GHG emissions, it could require us to incur costs to
monitor, keep records of, and report emissions of GHGs.
The EPA has also proposed the first New Source Performance Standards (NSPS) for GHG
emissions. The proposed GHG NSPS applies to carbon dioxide emissions from certain electric utility
generating units. This proposed NSPS does not regulate our operations, but if EPA were to promulgate
a GHG NSPS applicable to our operations we could incur significant costs to control our emissions and
comply with regulatory requirements.
Because of the lack of any comprehensive legislative program addressing GHGs, there is
continuing uncertainty regarding the further development of federal regulation of GHG-emitting
sources. Additionally, more than 20 states, either individually or as part of regional initiatives, have
begun taking actions to control and/or reduce GHG emissions primarily through the planned
development of GHG emission inventories and/or regional GHG cap and trade programs. Most of
these cap and trade programs work by requiring major sources of emissions to acquire and surrender
emission allowances. The federal, regional and local regulatory initiatives also could adversely affect the
marketability of the oil and natural gas we produce. The impact of such future programs cannot be
predicted, but we do not expect our operations to be affected any differently than other similarly
situated domestic competitors.
In addition to legislative and regulatory developments, plaintiffs have brought judicial actions
under common law theories against greenhouse gas emitting companies in recent years. For example,
municipal plaintiffs in Kivalina v. ExxonMobil Corporation, et al, alleged that the defendant
corporations’ contributions to global warming caused property damage associated with rising sea levels.
Although the plaintiffs in Kivalina were ultimately unsuccessful, there is a continuing litigation risk
associated with greenhouse gas-emitting activities.
OSHA and Other Laws and Regulation
We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA,
and comparable state statutes. These laws and the implementing regulations strictly govern the
protection of the health and safety of employees. The OSHA hazard communication standard, the EPA
community right- to- know regulations under the Title III of CERCLA and similar state statutes
require that we organize and/or disclose information 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 we are in substantial compliance with these applicable
requirements and with other OSHA and comparable requirements.
We believe that we are in substantial compliance with all existing environmental laws and
regulations applicable to our current operations and that our continued compliance with existing
requirements will not have a material adverse impact on our financial condition and results of
operations. We did not incur any material capital expenditures for remediation or pollution control
activities for the years ended December 31, 2013 or 2012. Additionally, we are not aware of any
environmental issues or claims that will require material capital expenditures during 2014 or that will
otherwise have a material impact on our financial position or results of operations in the future.
However, we cannot assure you that the passage of more stringent laws and regulations in the future
will not have a negative impact our business activities, financial condition or results of operations.
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Offices
We currently lease approximately 31,000 square feet of office space in Austin, Texas at 807 Las
Cimas Parkway, Austin, Texas 78746, where our principal offices are located. The primary lease expires
in April 2017. We also lease field offices in Canadian, Texas and McAlester, Oklahoma.
Employees
As of December 31, 2013, we had 91 employees, including 31 technical (geosciences, engineering,
land), 22 field operations, 29 corporate (finance, accounting, planning, business development, IT, office
management) and 9 management. None of these employees are represented by labor unions or covered
by any collective bargaining agreement. We consider our relations with our employees to be
satisfactory. From time to time we utilize the services of independent contractors to perform various
field and other services as needed.
Available information
We are required to file annual, quarterly and current reports, proxy statements and other
information with the SEC. Our reports filed with the SEC are made available to read and copy at the
SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain
information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed
with the SEC are also made available on its website at www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange under the symbol
‘‘JONE.’’ 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.
Through our website, www.jonesenergy.com, you can access, free of charge, electronic copies of all
of the documents that we file with the SEC, including our annual reports on Form 10-K, quarterly
reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports.
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 on Form 10-K, 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.
Drilling for and producing oil, natural gas and NGLs 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, natural gas and NGLs
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.
In addition, our cost of drilling, completing and operating wells is often uncertain before drilling
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commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including
the following:
(cid:127) 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;
(cid:127) pressure or irregularities in geological formations;
(cid:127) shortages of or delays in obtaining equipment and qualified personnel;
(cid:127) equipment failures or accidents;
(cid:127) fires and blowouts;
(cid:127) adverse weather conditions, such as hurricanes, blizzards and ice storms;
(cid:127) declines in oil, natural gas and NGL prices;
(cid:127) limited availability of financing at acceptable rates;
(cid:127) title problems; and
(cid:127) limitations in the market for oil, natural gas and NGLs.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques,
which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed
by us and our service providers. Risks that we face while drilling include, but are not limited to, the
following:
(cid:127) landing our wellbore in the desired drilling zone;
(cid:127) staying in the desired drilling zone while drilling horizontally through the formation;
(cid:127) running our casing the entire length of the wellbore; and
(cid:127) running tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to, the following:
(cid:127) the ability to fracture stimulate the planned number of stages;
(cid:127) the ability to run tools the entire length of the wellbore during completion operations; and
(cid:127) the ability to successfully clean out the wellbore after completion of the final fracture stimulation
stage.
The results of our drilling in new or emerging formations are more uncertain initially than drilling
results in areas that are more developed and have a longer history of established production. Newer or
emerging formations and areas have limited or no production history and, consequently, we are more
limited in assessing future drilling results in these areas.
The value of our undeveloped acreage could decline if drilling results are unsuccessful.
The success of our horizontal drilling and completion techniques can only be evaluated over time
as more wells are drilled and production profiles are established over a sufficiently long time period. If
our drilling results are less than anticipated or we are unable to execute our drilling program because
of capital constraints, lease expirations, access to gathering systems, declines in oil, natural gas and
NGL prices and/or other factors, the return on our investment in these areas may not be as attractive
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as we anticipate. Further, as a result of any of these developments we could incur material write-downs
of our oil and gas properties and the value of our undeveloped acreage could decline in the future.
Our business requires substantial capital expenditures, and we may be unable to obtain needed capital or
financing on satisfactory terms or at all.
Our exploration, exploitation, development and acquisition activities require substantial capital
expenditures. Our total capital expenditures for 2013 were $240 million and our budgeted capital
expenditures for 2014 are $350 million. Historically, we have funded development and operating
activities primarily through a combination of equity capital raised from a private equity partner and our
initial public offering, through borrowings under our bank credit facilities and through internal
operating cash flows. We intend to finance the majority of our capital expenditures predominantly with
cash flows from operations. If necessary, we may also access capital through proceeds from potential
asset dispositions, borrowings under our credit facilities and the issuance of debt and equity securities.
Our cash flow from operations and access to capital are subject to a number of variables, including:
(cid:127) the estimated quantities of our oil, natural gas and NGL reserves;
(cid:127) the amount of oil, natural gas and NGLs we produce from existing wells;
(cid:127) the prices at which we sell our production;
(cid:127) the costs of developing and producing our oil, natural gas and NGL reserves;
(cid:127) take-away capacity;
(cid:127) our ability to acquire, locate and produce new reserves;
(cid:127) the ability and willingness of banks to lend to us; and
(cid:127) our ability to access the equity and debt capital markets.
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 conduct our operations at expected
levels. Our senior secured revolving credit facility and our second lien term loan facility may restrict
our ability to obtain new debt financing. 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, natural gas and NGLs production or reserves, and in some areas a loss of
properties.
External financing may be required in the future to fund our growth. We may not be able to
obtain additional financing, and financing under our senior secured revolving credit facility and our
second lien term loan facility may not be available in the future. Without additional capital resources,
we may be unable to pursue and consummate acquisition opportunities as they become available, and
we may be forced to limit or defer our planned oil, natural gas and NGLs development program, which
will adversely affect the recoverability and ultimate value of our oil, natural gas and NGLs properties,
in turn negatively affecting our business, financial condition and results of operations.
The development of our proved undeveloped reserves in our areas of operation may take longer and may
require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves
may not be ultimately developed or produced.
Approximately 44% of our total estimated proved reserves were classified as proved undeveloped
as of December 31, 2013. Development of these reserves may take longer and require higher levels of
capital expenditures than we currently anticipate. In addition, declines in commodity prices could cause
us to reevaluate our development plans and delay or cancel development. Delays in the development of
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our reserves or increases in costs to drill and develop such reserves will reduce the future net revenues
estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays
in the development of reserves could cause us to have to reclassify our proved reserves as unproved
reserves.
A substantial or extended decline in oil, natural gas or NGL prices may adversely affect our business,
financial condition or results of operations and our ability to meet our capital expenditure obligations and
financial commitments.
The price we receive for our oil, natural gas and NGLs heavily influences 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. The markets for oil, natural gas and NGLs historically have been volatile and 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:
(cid:127) regional and worldwide economic conditions impacting the supply and demand for oil, natural
gas and NGLs;
(cid:127) the actions of the Organization of Petroleum Exporting Countries;
(cid:127) the price and quantity of imports of foreign oil, natural gas and NGLs;
(cid:127) political conditions regionally, domestically or in other oil and gas-producing regions;
(cid:127) the level of domestic and global oil and natural gas exploration and production;
(cid:127) the level of domestic and global oil and natural gas inventories;
(cid:127) localized supply and demand fundamentals and transportation availability;
(cid:127) weather conditions and natural disasters;
(cid:127) domestic, local and foreign governmental regulations and taxes;
(cid:127) speculation as to the future price of oil, natural gas and NGLs and the speculative trading of oil,
natural gas and NGLs;
(cid:127) trading prices of futures contracts;
(cid:127) price and availability of competitors’ supplies of oil, natural gas and NGLs;
(cid:127) technological advances affecting energy consumption;
(cid:127) the price and availability of alternative fuels; and
(cid:127) the impact of energy conservation efforts.
NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have
different uses and different pricing characteristics. NGLs comprised 28% of our 2013 production, and
we realized an average price of $33.30 per barrel. An extended decline in NGL prices could materially
and adversely affect our future business, financial condition and results of operations.
Substantially all of our production is sold to purchasers under contracts with market-based prices.
Lower oil, natural gas and NGL prices will reduce our cash flows and the present value of our reserves.
If oil, natural gas and NGL prices deteriorate, we anticipate that the borrowing base under our senior
secured revolving credit facility, which is revised periodically, may be reduced, which would negatively
impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would
require us to borrow to fund our capital budget. Lower oil, natural gas and NGL prices may also
reduce the amount of oil, natural gas and NGLs that we can produce economically. Substantial
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decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our
identified drilling locations. This may result in significant downward adjustments to our estimated
proved reserves. As a result, a substantial or extended decline in oil, natural gas or NGL prices may
materially and adversely affect our future business, financial condition, results of operations, liquidity or
ability to finance planned capital expenditures.
Unless we replace our reserves, our reserves and production will naturally decline, which would adversely
affect our business, financial condition and results of operations.
Unless we conduct successful development and acquisition activities or acquire properties
containing proved reserves, our proved reserves will decline as those reserves are produced. Producing
oil and natural gas reservoirs generally are characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. Our future oil, natural gas and NGL
reserves and production, and therefore our cash flows and income, are highly dependent on our success
in efficiently developing our current reserves and economically finding or acquiring additional
recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs. 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 will be adversely affected.
Our identified drilling locations are scheduled to be drilled 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 or delay associated expected production. In addition, we may not be able to raise the amount of
capital that would be necessary to drill a substantial portion of our identified drilling locations.
Our management team has identified and scheduled certain drilling locations as an estimation of
our future multi-year drilling activities on our existing acreage. These drilling locations represent a
significant part of our growth strategy. Our drilling locations are in various stages of evaluation, ranging
from a location that is ready to drill to a location that will require substantial additional interpretation.
There is no way to predict in advance of drilling and testing whether any particular location will yield
oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be
economically viable. Similarly, the use of technologies and the study of producing fields in the same
area of producing wells 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 sufficient quantities to be
economically viable. Even if sufficient quantities of oil or natural gas exist, we may damage the
potentially productive hydrocarbon bearing formation or experience mechanical difficulties while
drilling or completing the well, resulting in a reduction in production from or abandonment of the well.
If we drill additional wells that we identify as dry holes in our current and future drilling locations, our
drilling success rate may decline and materially harm our business. In addition, our ability to drill and
develop these drilling locations depends on a number of uncertainties, including oil, natural gas and
NGL prices, the availability and cost of capital, drilling and production costs, the availability of drilling
services and equipment, drilling results, lease expirations, gathering systems, marketing and pipeline
transportation constraints, regulatory approvals and other factors. In addition, a number of our
identified drilling locations are associated with joint development agreements and if we do not meet
our obligation to drill the minimum number of wells specified in an agreement, we will lose the right to
continue to develop certain acreage covered by that agreement. Because of the uncertainty inherent in
these factors, we do not know if the numerous drilling locations we have identified will ever be drilled
or if we will be able to produce oil, natural gas or NGLs from these or any other 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.
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If commodity prices decrease, we may be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for
possible impairment. Based on prevailing commodity prices and specific market factors and
circumstances at the time of prospective impairment reviews, and the continuing evaluation of
development plans, production data, economics and other factors, we may be required to write down
the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Such
impairment may also result in a reduction in proved reserves, thereby increasing future depletion
charges per unit of production. We may incur impairment charges and related reductions in proved
reserves in the future, which could have a material adverse effect on our results of operations for the
periods in which such charges are taken.
Our estimated oil, natural gas and NGLs reserve quantities and future production rates are based on many
assumptions that may prove to be inaccurate. Any significant inaccuracies in these reserve estimates or the
underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves.
Our estimates of our proved reserve quantities are based upon our reserve report as of December 31,
2013. Reserve estimation is a subjective process of evaluating underground accumulations of oil, natural
gas and NGLs that cannot be measured in an exact manner. Reserves that are ‘‘proved reserves’’ are
those estimated quantities of oil, natural gas and NGLs 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 process of estimating oil, natural gas and NGL reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological, engineering and economic data for
each reservoir, and these reports rely upon various assumptions, including assumptions regarding future
oil, natural gas and NGL prices, production levels, and operating and development costs. As a result,
estimated quantities of proved reserves and projections of future production rates and the timing of
development expenditures may prove to be inaccurate. Quantities of proved reserves are estimated
based on pricing conditions in existence during the period of assessment and costs at the end of the
period of assessment. Changes to oil, natural gas and NGL 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 reserve estimates.
Over time, we may make material changes to reserve estimates taking into account the results of
actual drilling and production. Any significant variance in our assumptions and actual results could
greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and
NGLs attributable to any particular group of properties, the classifications of reserves based on risk of
recovery, and estimates of the future net cash flows. In addition, changes in future production cost
assumptions could have a significant effect on our proved reserve quantities.
If we do not fulfill our obligation to drill minimum numbers of wells specified in our joint development
agreements, we will lose the right to develop the undeveloped acreage associated with the agreement and any
proved undeveloped reserves attributable to such undeveloped acreage.
If we do not meet our obligation to drill the minimum number of wells specified in a joint
development agreement, we will lose the right to continue to develop the undeveloped acreage covered
by the agreement, which would result in the loss of any proved undeveloped reserves attributable to
such undeveloped acreage.
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The standardized measure of discounted future net cash flows from our proved reserves will not necessarily be
the same as the current market value of our estimated oil, natural gas and NGL reserves.
You should not assume that the standardized measure of discounted future net cash flows from
our proved reserves is the current market value of our estimated oil, natural gas and NGL reserves. In
accordance with SEC requirements, we based the discounted future net cash flows from our proved
reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodities
prices for the preceding 12 months without giving effect to derivative transactions. Actual future net
cash flows from our oil and natural gas properties will be affected by factors such as:
(cid:127) commodity price hedging and actual prices we receive for oil, natural gas and NGLs;
(cid:127) actual cost of development and production expenditures;
(cid:127) the amount and timing of actual development and production; and
(cid:127) changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the
development and production of oil and natural gas properties will affect the timing and amount of
actual future net revenues from proved reserves, and thus their actual present value. In addition, the
10% discount factor we use when calculating standardized measure may not be the most appropriate
discount factor based on interest rates in effect from time to time and risks associated with our
company or the oil and natural gas industry in general. Prior to the consummation of the IPO, as a
limited liability company, we generally were not historically subject to entity-level taxation. Accordingly,
our standardized measure for historical periods does not provide for federal or state corporate income
taxes because taxable income was passed through to our equity holders. However, upon consummation
of the IPO, we became subject to entity-level taxation for federal income tax purposes, and our future
income taxes will be dependent upon our future taxable income.
If oil prices decline by $10.00 per Bbl, then our standardized measure as of December 31, 2013
excluding hedging impacts would decrease approximately $120.0 million. If natural gas prices decline by
$1.00 per Mcf, then our standardized measure as of December 31, 2013 excluding hedging impacts
would decrease by approximately $108.4 million.
Over 97% of our estimated proved reserves are located in the Anadarko and Arkoma basins in the Texas
Panhandle and Oklahoma, making us vulnerable to risks associated with operating in one geographic area.
Over 97% of our estimated proved reserves as of December 31, 2013 were located in the
Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma, approximately 65% of which are
being produced from the Cleveland formation from properties located in four contiguous counties of
Texas and Oklahoma. 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, availability of
equipment, facilities, personnel or services market limitations or interruption of the processing or
transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand
may become more pronounced within specific geographic oil and natural gas producing areas such as
our properties producing from the Cleveland formation, which may cause these conditions to occur
with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of
our portfolio of properties, a number of our properties could experience any of the same conditions at
the same time, resulting in a relatively greater impact on our results of operations than they might have
on other companies that have a more diversified portfolio of properties. Such delays or interruptions
could have a material adverse effect on our financial condition and results of operations.
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Our customer base is concentrated, and the loss of any one of our key customers could, therefore, adversely
affect our financial condition and results of operations.
Historically, we have been dependent on a few customers for a significant portion of our revenue.
For the year ended December 31, 2013 purchases by our top four customers accounted for
approximately 15%, 13%, 13% and 13%, respectively, of our total oil, natural gas and NGL sales. This
concentration of customers may increase our overall exposure to credit risk, and customers will likely
be similarly affected by changes in economic and industry conditions. To the extent that any of our
major purchasers reduces their purchases of oil, natural gas or NGLs or defaults on their obligations to
us, our financial condition and results of operations could be adversely affected.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any
inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of businesses that complement or expand our current
business. We may not be able to identify attractive acquisition opportunities. Even if we do identify
attractive acquisition opportunities, we may not be able to complete the acquisition or do so on
commercially acceptable terms.
In addition, our senior secured revolving credit facility and our second lien term loan facility
impose certain limitations on our ability to enter into mergers or combination transactions. Our senior
secured revolving credit facility and our second lien term loan facility also limit our ability to incur
certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
Any acquisition involves potential risks, including, among other things:
(cid:127) the validity of our assumptions about estimated proved reserves, future production, commodity
prices, revenues, capital expenditures, operating expenses and costs;
(cid:127) an inability to successfully integrate the assets we acquire;
(cid:127) an inability to obtain satisfactory title to the assets we acquire;
(cid:127) a decrease in our liquidity by using a significant portion of our available cash or borrowing
capacity to finance acquisitions;
(cid:127) a significant increase in our interest expense or financial leverage if we incur additional debt to
finance acquisitions;
(cid:127) the assumption of unknown liabilities, losses or costs for which we obtain no or limited
indemnity or other recourse;
(cid:127) the diversion of management’s attention from other business concerns;
(cid:127) an inability to hire, train or retain qualified personnel to manage and operate our growing
assets; and
(cid:127) the occurrence of other significant changes, such as impairment of oil and natural gas properties,
goodwill or other intangible assets, asset devaluation or restructuring charges.
Our decision to acquire a property will depend in part on the evaluation of data obtained from
production reports and engineering studies, geophysical and geological analyses and seismic data and
other information, the results of which are often inconclusive and subject to various interpretations.
The success of any completed acquisition, including the Sabine acquisition, will depend on our
ability to integrate effectively the acquired assets into our existing operations. The process of
integrating acquired assets may involve unforeseen difficulties and may require a disproportionate
amount of our managerial and financial resources. In addition, even if we successfully integrate an
37
acquisition, it may not be possible to realize the full benefits we may expect in estimated proved
reserves, production volume, cost savings from operating synergies or other benefits anticipated from
an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an
acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural
gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined
assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize
the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
Deficiencies of title to our leased interests could significantly affect our financial condition.
It is our practice, in acquiring oil and natural gas leases or undivided interests in oil and natural
gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title
to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease
brokers or landmen who perform the fieldwork in examining records in the appropriate governmental
or county clerk’s office to determine mineral ownership before we acquire an oil and gas lease or other
developed rights in a specific mineral interest.
Prior to the drilling of an oil or gas well, it is the normal practice in our industry for the operator
of the well to obtain a drilling title opinion from a qualified title attorney to ensure there are no
obvious title defects on the property on which the well is to be located. The title attorney would
typically research documents that are of record, including liens, taxes and all applicable contracts that
burden the property. Frequently, as a result of such examinations, certain curative work must be
undertaken to correct defects in the marketability of the title, and such curative work entails expense.
Our failure to completely cure any title defects may invalidate our title to the subject property and
adversely impact our ability in the future to increase production and reserves. Additionally, because a
less strenuous title review is conducted on lands where a well has not yet been scheduled, undeveloped
acreage has greater risk of title defects than developed acreage. Any title defects or defects in
assignment of leasehold rights in properties in which we hold an interest may adversely impact our
ability in the future to increase production and reserves, which could have a material adverse effect on
our business, financial condition and results of operations.
We conduct a substantial portion of our operations through joint development agreements with
third parties. Certain of our joint development agreements include drill-to-earn arrangements, whereby
we are assigned title to properties from the third party after we complete wells and, in the case of
certain counterparties, after completion reports relating to the wells have been approved by regulatory
authorities whose approval may be delayed. Furthermore, certain of our joint development agreements
specify that assignments are only to occur when the wells are capable of producing hydrocarbons in
paying quantities. These additional conditions to assignment of title may from time to time apply to
wells of substantial value. If one of our counterparties assigned title to a well in which we had earned
an interest (according to our joint development agreement) to a third party, our title to such a well
could be adversely impacted. In addition, if one of our counterparties becomes a debtor in a
bankruptcy proceeding, or is placed into receivership, or enters into an assignment for the benefit of
creditors, after we had earned ownership of, but before we had received title to, a well, certain
creditors of the counterparty may have rights in that well that would rank prior to ours.
Our hedging strategy may be ineffective in reducing the impact of commodity price volatility from our cash
flows, which could result in financial losses or could reduce our income.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the
prices of oil, natural gas and NGLs, we enter into commodity derivative contracts for a significant
portion of our oil, natural gas and NGLs production that could result in both realized and unrealized
hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and
scope of our commodity derivative contracts. For example, some of the commodity derivative contracts
38
we utilize are based on quoted market prices, which may differ significantly from the actual prices we
realize in our operations for oil, natural gas and NGLs. In addition, our senior secured revolving credit
facility and our second lien term loan facility limit the aggregate notional volume of commodities that
can be covered under commodity derivative contracts we can enter into and, as a result, we will
continue to have direct commodity price exposure on the unhedged portion of our production volumes.
For the years ending December 31, 2014, 2015, 2016 and 2017, approximately 38%, 59%, 69% and
73%, respectively, of our estimated total oil, natural gas and NGL production, based on our reserve
report as of December 31, 2013, will not be covered by commodity derivative contracts.
Our policy has been to hedge a significant portion of our estimated oil, natural gas and NGLs
production. However, our price hedging strategy and future hedging transactions will be determined at
our discretion. We are not under an obligation to hedge a specific portion of our production. The
prices at which we hedge our production in the future will be dependent upon commodity prices at the
time we enter into these transactions, which may be substantially higher or lower than current oil,
natural gas and NGLs prices. Accordingly, our price hedging strategy may not protect us from
significant declines in oil, natural gas and NGL prices received for our future production. Conversely,
our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is
also possible that a larger percentage of our future production will not be hedged as compared with
past years, which would result in our oil and natural gas revenues becoming more sensitive to
commodity price changes.
In addition, our actual future production may be significantly higher or lower than we estimate at
the time we enter into commodity derivative contracts for such period. If the actual amount is higher
than we estimate, we will have greater commodity price exposure than we intended. If the actual
amount is lower than the notional amount of our commodity derivative contracts, we might be forced
to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow
from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity.
There may be a change in the expected differential between the underlying commodity price in the
commodity derivative contract and the actual price received, which may result in payments to our
derivative counterparty that are not offset by our receipt of payments for our production in the field.
As a result of these factors, our commodity derivative activities may not be as effective as we
intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase
the volatility of our cash flows.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under
a derivative contract. Disruptions in the financial markets could lead to sudden changes in a
counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative
contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to
perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited
depending upon market conditions. Currently our entire hedge portfolio is hedged directly with banks
in our credit agreements, thus allowing hedging without any margin requirements.
During periods of falling commodity prices, our hedge receivable positions generally increase,
which increases our counterparty credit exposure. If the creditworthiness of our counterparties
deteriorates and results in their nonperformance, we could incur a significant loss.
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The adoption of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act,
could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk,
interest rate and other risks associated with our business.
We use commodity derivatives to manage our commodity price risk. The U.S. Congress adopted
comprehensive financial reform legislation that, among other things, establishes comprehensive federal
oversight and regulation of over-the-counter derivatives and many of the entities that participate in that
market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading
Commission, or the CFTC, and the SEC, along with certain other regulators, must promulgate final
rules and regulations to implement many of its provisions relating to over-the-counter derivatives.
While some of these rules have been finalized, some have not and, as a result, the final form and
timing of the implementation of the new regulatory regime affecting commodity derivatives remains
uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act
establishing position limits for certain energy commodity futures and options contracts and
economically equivalent swaps, futures and options. The position limit levels set the maximum amount
of covered contracts that a trader may own or control separately or in combination, net long or short.
The final rules also contained limited exemptions from position limits which would be phased in over
time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule
was challenged in court by two industry associations and was vacated and remanded by a federal
district court. Since that time, the CFTC has reproposed the rule in substantially the same form as the
rule that was vacated by the court, but with certain non-substantive changes in response to the court’s
decision. The CFTC has sought comment on the position limits rule as reproposed, but has yet to issue
its final rule. The CFTC also has withdrawn its appeal of the court order vacating the original position
limits rule.
If these or similar position limits go into effect in the future, the timing of implementation of the
final rules, their applicability to, and impact on, us and the ultimate success of any legal challenge to
their validity remain uncertain, and they could have a material adverse impact on us by affecting the
prices of or market for commodities relevant to our operations and/or by reducing the availability to us
of commodity derivatives.
The Dodd-Frank Act also imposes a number of other new requirements on certain
over-the-counter derivatives and subjects certain swap dealers and major swap participants to significant
new regulatory requirements, which in certain cases may cause them to conduct their activities through
new entities that may not be as creditworthy as our current counterparties, all of which may have a
material adverse effect on us. The impact of this regulatory regime on the availability, pricing and
terms and conditions of commodity derivatives remains uncertain, but the final requirements could have
a materially adverse effect on our ability to hedge our exposure to commodity prices.
If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated
under it and the changes to the nature of the derivatives markets, 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. In addition, the Dodd-Frank Act was intended, in
part, to reduce the volatility of commodity prices, which some legislators attributed to speculative
trading in derivatives and commodity contracts related to oil, natural gas and NGLs. Our revenue
could, therefore, be adversely affected if commodity prices were to decrease.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and
development may be eliminated as a result of future legislation.
From time to time, legislation is introduced that would, if enacted, make significant changes to
U.S. tax laws. These proposed changes have included repealing many tax incentives and deductions that
40
are currently used by U.S. oil and gas companies and imposing new fees. Among others, proposed
changes have included: elimination of the ability to fully deduct intangible drilling costs in the year
incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the
domestic manufacturing tax deduction for oil and gas companies; increase in the geological and
geophysical cost amortization period for independent producers; and implementation of a fee on
non-producing federal oil and gas leases. The passage of legislation containing some or all of these
provisions or any other similar change in U.S. federal income tax law could eliminate or postpone
certain tax deductions that are currently available to us with respect to oil and natural gas exploration
and development, and any such change could have a material adverse effect on our business, financial
condition and results of operations.
We may be unable to compete effectively with larger companies, which may adversely affect our ability to
generate sufficient revenues.
The oil and natural gas industry is intensely competitive, and we compete with other companies
that have greater resources than us. Many of our larger competitors not only drill for and produce oil
and natural gas, but also engage in refining operations and market petroleum and other products on a
regional, national or worldwide basis. These companies may have a greater ability to continue drilling
activities during periods of low oil, natural gas and NGL prices, to contract for drilling equipment, to
secure trained personnel, and to absorb the burden of present and future federal, state, local and other
laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling
rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation
activities and has caused significant price increases. Competition has been strong in hiring experienced
personnel, particularly in the engineering and technical, accounting and financial reporting, tax and
land departments. In addition, competition is strong for attractive oil and natural gas producing
properties, oil and natural gas companies, and undeveloped leases and drilling rights. Any inability to
compete effectively with larger companies could have a material adverse impact on our financial
condition and results of operations.
The oil and natural gas industry is characterized by rapid and significant technological
advancements and introductions of new products and services using new technologies. As others use or
develop new technologies, we may be placed at a competitive disadvantage or competitive pressures
may force us to implement those new technologies at substantial costs. In addition, other oil and
natural gas companies may have greater financial, technical, and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to implement new technologies before
we can. We may not be able to respond to these competitive pressures and implement new technologies
on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the
future were to become obsolete or if we are unable to use the most advanced commercially available
technology, our business, financial condition and results of operations could be materially adversely
affected.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our
projects.
We frequently own less than 100% of the working interest in the oil and gas leases on which we
conduct operations, and other parties will own the remaining portion of the working interest. Financial
risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells
is shared by more than one person. We could be held liable for joint activity obligations of other
working interest owners, such as nonpayment of costs and liabilities arising from the actions of other
working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the
likelihood that some of these working interest owners, particularly those that are smaller and less
established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling
41
to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any
of our project partners do not pay their share of such costs, we would likely have to pay those costs,
and we may be unsuccessful in any efforts to recover these costs from our partners, which could
materially adversely affect our financial position.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services as well as
fees for the cancellation of such services could adversely affect our ability to execute development and
exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated
cash flow.
We utilize third-party services to maximize the efficiency of our operation. The cost of oil field
services typically fluctuates based on demand for those services. We may not be able to contract for
such services on a timely basis, or the cost of such services may not remain at a satisfactory or
affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including
hydraulic fracturing equipment, supplies and personnel necessary for horizontal drilling, could delay or
adversely affect our development and exploitation operations, which could have a material adverse
effect on our financial condition and results of operations.
Our business depends in part on pipelines, transportation and gathering systems and processing
facilities owned by others. Any limitation in the availability of those facilities could interfere with our
ability to market our oil, natural gas and NGLs production and could harm our business.
The marketability of our oil, natural gas and NGLs production depends in part on the availability,
proximity and capacity of pipelines and other transportation methods, such as trucks, gathering systems
and processing facilities owned by third parties. The amount of oil, natural gas and NGLs that can be
produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due
to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted
capacity on such systems. Also, the transfer of our oil, natural gas and NGLs on third-party pipelines
may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our
access to transportation options, including trucks owned by third parties, can also be affected by U.S.
federal and state regulation of oil and gas production and transportation, general economic conditions
and changes in supply and demand. The curtailments arising from these and similar circumstances may
last from a few days to several months. In many cases, we are provided only with limited, if any, notice
as to when these circumstances will arise and their duration. Any significant curtailment in gathering
system or transportation or processing facility capacity could reduce our ability to market our oil,
natural gas and NGLs production and harm our business.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural
gas 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.
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. 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:
(cid:127) environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic
gas or other pollution into the environment, including groundwater contamination;
(cid:127) adverse weather conditions and natural disasters;
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(cid:127) abnormally pressured formations;
(cid:127) facility or equipment malfunctions;
(cid:127) mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
(cid:127) fires, explosions and ruptures of pipelines;
(cid:127) personal injuries and death; and
(cid:127) 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:
(cid:127) injury or loss of life;
(cid:127) damage to and destruction of property, natural resources and equipment;
(cid:127) pollution and other environmental damage and associated clean-up responsibilities;
(cid:127) regulatory investigations, penalties or other sanctions;
(cid:127) suspension of our operations; and
(cid:127) repair and remediation costs.
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.
Our oil and natural gas exploration and production 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. Failure or delay in obtaining regulatory approvals or drilling
permits could have a material adverse effect on our ability to develop our properties, and receipt of
drilling permits with onerous conditions could increase our compliance costs. In addition, regulations
regarding conservation practices and the protection of correlative rights affect our operations by
limiting the quantity of oil, natural gas and NGLs we may produce and sell.
We are subject to federal, state and local laws and regulations as interpreted and enforced by
governmental authorities possessing jurisdiction over various aspects of the exploration, production and
transportation of oil, natural gas and NGLs, as well as safety matters. Legal requirements are
frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of
compliance with these requirements or their ultimate effect on our operations. We may be required to
make significant expenditures to comply with governmental laws and regulations. The discharge of oil,
natural gas, NGLs or other pollutants into the air, soil or water may give rise to significant liabilities on
our part to the government, and third parties and may require us to incur substantial costs for
remediation.
See ‘‘Item 1. Business—Regulations’’ for a further description of the laws and regulations that
affect us.
Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to
a failure to comply with environmental regulations or a release of hazardous substances into the environment.
We may incur significant costs and liabilities as a result of environmental requirements applicable
to the operation of our wells, gathering systems and other facilities. These costs and liabilities could
43
arise under a wide range of federal, state and local environmental laws and regulations, including, for
example:
(cid:127) the Clean Air Act, or CAA, and comparable state laws and regulations that impose obligations
related to air emissions;
(cid:127) the Clean Water Act and Oil Pollution Act, or OPA, and comparable state laws and regulations
that impose obligations related to discharges of pollutants into regulated bodies of water;
(cid:127) the Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose
requirements for the handling and disposal of waste from our facilities;
(cid:127) the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA,
and comparable state laws that regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated by us or at locations to which
we have sent waste for disposal;
(cid:127) the Environmental Protection Agency’s, or EPA’s, community right to know regulations under
the Title III of CERCLA and comparable state laws that require that we organize and/or
disclose information about hazardous materials used or produced in our operations;
(cid:127) the Occupational Safety and Health Act, or OSHA, which establishes workplace standards for
the protection of the health and safety of employees, including the implementation of hazard
communications programs designed to inform employees about hazardous substances in the
workplace, potential harmful effects of these substances, and appropriate control measures;
(cid:127) the National Environmental Policy Act, or NEPA, which requires federal agencies to evaluate
major agency actions having the potential to significantly impact the environment and which may
require the preparation of Environmental Assessments and more detailed Environmental Impact
Statements that may be made available for public review and comment;
(cid:127) the Migratory Bird Treaty Act, which implements various treaties and conventions between the
United States and certain other nations for the protection of migratory birds and, pursuant to
which the taking, killing, or possessing of migratory birds is unlawful without a permit, thereby
potentially requiring the implementation of operating restrictions or a temporary, seasonal, or
permanent ban on operations in affected areas; and
(cid:127) the Endangered Species Act, or ESA, and analogous state laws, which seek to ensure that
activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy
or modify the critical habitat of such species.
We may incur significant delays, costs and liabilities as a result of federal, state and local
environmental, health and safety requirements applicable to 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 product transportation pipelines or other operations;
regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes;
limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness,
wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution
from former operations such as plugging abandoned wells or closing earthen pits; and/or impose
substantial liabilities for spills, pollution or failure to comply with regulatory filing requirements. In
addition, 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 trigger a variety
of administrative, civil and criminal enforcement measures, including the assessment of monetary
penalties, the imposition of remedial requirements, and the issuance of orders enjoining future
operations. Certain environmental statutes, including the RCRA, CERCLA, the federal OPA and
44
analogous state laws and regulations, impose strict joint and several liability for costs required to clean
up and restore sites where petroleum or hazardous substances or other waste products have been
disposed of or otherwise released. More stringent laws and regulations, including laws related to
climate change and greenhouse gases, may be adopted in the future. The trend of more expensive 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.
Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of hazardous substances or other
waste products into the environment. We are also subject to many other environmental requirements
delineated in ‘‘Business—Environmental Matters and Regulation.’’
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing and other oil and gas
production activities as well as governmental reviews of such activities could result in increased costs,
additional operating restrictions or delays, which could adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of
natural gas and/or oil from dense subsurface rock formations. The process involves the injection of
water, sand and chemicals under pressure into the formation to fracture the surrounding rock and
stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and
natural gas drilling and completion programs. The process is typically regulated by state oil and natural
gas commissions. However, the EPA recently asserted federal regulatory authority over certain
hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act, or SDWA, in
states where EPA is the permitting authority and released guidance in February 2014 on regulatory
requirements for companies that plan to conduct hydraulic fracturing using diesel in those states. In
addition, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate
rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used
in oil and gas exploration and production. Congress has also considered legislation to provide for
federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the
fracturing process.
Some states, including those in which we operate, have adopted, and other states are considering
adopting, regulations that could impose more stringent permitting, disclosure and well construction
requirements on hydraulic fracturing operations under certain circumstances. For example, Texas
adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas, or TRRC, and
the public of certain information regarding the components of the fluids used in the hydraulic
fracturing process. On December 13, 2011, the TRRC finalized regulations requiring public disclosure
of chemicals in fluids used in the hydraulic fracturing process for drilling permits issued after
February 1, 2012. In addition, on October 20, 2011, Louisiana adopted new regulations for hydraulic
fracturing operations in the state. These new regulations require hydraulic fracturing operators to
publicly disclose the volume of hydraulic fracturing fluid, the type, trade name, supplier and volume of
additives, and a list of chemical compounds contained in the additive, along with its maximum
concentration, subject to certain trade secret protections. However, trade secret chemicals must be
identified by their chemical family. The mandatory disclosure of information regarding the constituents
of hydraulic fracturing fluids could make it easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based upon allegations that specific chemicals used in the
fracturing process could adversely affect the environment. In addition, the Oklahoma Corporation
Commission has adopted rules prohibiting water pollution resulting from hydraulic fracturing
operations and requiring disclosure of chemicals used in hydraulic fracturing.
Texas has also authorized the Texas Commission on Environmental Quality to suspend water use
rights for oil and gas users in the event of serious drought conditions and has imposed more stringent
emissions, monitoring, inspection, maintenance, and repair requirements on Barnett Shale operators to
45
minimize Volatile Organic Compound, or VOC, releases. Also, Louisiana requires operators to
minimize releases of gases into the open air after hydraulic fracturing in certain urban areas.
In addition to state laws, 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. In the
event state, local, or municipal legal restrictions are adopted in areas where we are currently
conducting operations, or in the future plan to conduct operations, we may incur additional costs to
comply with such requirements that may be significant in nature, experience delays or curtailment in
the pursuit of exploration, development, or production activities, and perhaps even be precluded from
drilling wells.
There are also certain governmental reviews either underway or being proposed that focus on
environmental aspects of hydraulic fracturing practices. The White House Council on Environmental
Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee
of the United States House of Representatives has conducted an investigation of hydraulic fracturing
practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a
variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of
the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The
EPA released its first progress report on this study in December 2012 and expects to release a final
draft report for public comment and peer review in 2014. Moreover, the EPA announced on
October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities
and plans to propose pretreatment standards this year. In addition, the U.S. Department of Energy’s
Natural Gas Subcommittee of the Secretary of Energy Advisory Board conducted a review of hydraulic
fracturing issues and practices and made recommendations to better protect the environment from
drilling using hydraulic fracturing completion methods. These ongoing or proposed studies, depending
on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate
hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other
statutory and/or regulatory mechanisms. President Obama created the Interagency Working Group on
Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with
coordinating and aligning federal agency research and scientific studies on unconventional oil and
natural gas resources.
Also, the U.S. Department of the Interior’s Bureau of Land Management, or BLM, is considering
rules regarding well stimulation, chemical disclosures and other requirements for hydraulic fracturing
on federal and Indian lands. BLM released a proposed rule requiring the disclosure of chemicals used
during hydraulic fracturing and addressing drilling plans, water management and wastewater disposal,
on federal and Indian lands in May 2012. However, BLM pulled back its proposal in January 2013 after
reviewing comments and published an updated proposed rule on May 24, 2013.
Further, on April 17, 2012, the EPA released final rules to subject all oil and gas operations
(production, processing, transmission, storage and distribution) to regulation under the New Source
Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or
NESHAPS, programs. These rules became effective on October 15, 2012. The EPA rules also include
NSPS standards for completions of hydraulically-fractured gas wells. These standards include the
reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with
pit flaring of gas not sent to the gathering line. The standards will be applicable to newly drilled and
fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS
include maximum achievable control technology, or MACT, standards for those glycol dehydrators and
storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards.
In October 2012, several challenges to the EPA’s rules were filed by various parties, including
environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this
litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. EPA issued a
final rule revising certain aspects of the rules on August 5, 2013. Depending on the outcome of such
46
judicial proceedings and regulatory actions, the rules may be further modified or rescinded or the EPA
may issue new rules. We are currently evaluating the effect these rules will have on our business.
Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to
compel the agency to make a determination as to whether standards of performance limiting methane
emissions from oil and gas sources are appropriate, and, if so, to promulgate performance standards for
methane emissions from the oil and gas sector, which was not addressed in the EPA rules that became
effective on October 15, 2012. The notice of intent also requested the EPA issue emission guidelines
for the control of methane emissions from existing oil and gas sources. Increased regulation and
attention given to the hydraulic-fracturing process could lead to greater opposition, including litigation,
to oil and gas production activities using hydraulic-fracturing techniques. Additional legislation or
regulation could also lead to operational delays or increased operating costs in the production of oil
and natural gas, including from the developing shale formations, or could make it more difficult to
perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of
regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new
oil and gas wells, increased compliance costs and time, which could adversely affect our financial
position, results of operations and cash flows.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased
operating costs and reduced demand for the oil, natural gas and NGLs we produce.
In December 2009, the EPA officially published its findings that emissions of carbon dioxide,
methane and other greenhouse gases, or GHGs, present an endangerment to public 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. Based on its findings, the EPA has begun adopting and
implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean
Air Act, including one rule that requires a reduction in emissions of GHGs from motor vehicles and
another that regulates emissions of GHGs from certain large stationary sources. Since January 2, 2011,
the EPA has required new or modified stationary sources that emit GHGs at levels above regulatory
and statutory thresholds to apply for a Prevention of Significant Deterioration, or PSD, permit under
the Clean Air Act. The EPA set the current regulatory thresholds in its ‘‘Tailoring Rule,’’ which was
intended to avoid the need for large numbers of relatively small GHG-emitting sources to obtain a
permit under the Clean Air Act. The EPA has also indicated that it may revise its Tailoring Rule
carbon dioxide equivalent thresholds downward in a future rulemaking, which would likely subject
additional stationary sources to GHG permitting requirements.
The EPA has also proposed GHG New Source Performance Standards under the Clean Air Act
for certain electric utility generating units and may propose GHG NSPS for additional source
categories in the future. In addition, on October 30, 2009, the EPA published a final rule requiring the
reporting of GHG emissions from specified large GHG emission sources in the United States. On
November 9, 2010, the EPA issued final rules to expand its existing GHG reporting rule to include
onshore oil and natural gas production, processing, transmission, storage and distribution facilities with
reporting of GHG emissions from such facilities required on an annual basis. The first reports were
due in 2012 for emissions occurring in 2011.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce
emissions of GHGs and almost one-half of the states have already taken legal measures to reduce
emissions of GHGs primarily through the planned development of GHG emission inventories and/or
regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce
emissions of GHGs 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 or
reporting requirements. Any such legislation or regulatory programs could also increase the cost of
consuming, and thereby reduce demand for, the oil, natural gas and NGLs we produce. Consequently,
47
legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our
business, financial condition and results of operations.
In addition, there has been public discussion that climate change may be associated with extreme
weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms,
as well as rising sea levels. Another possible consequence of climate change is increased volatility in
seasonal temperatures. Some studies indicate that climate change could cause some areas to experience
temperatures substantially colder than their historical averages. Extreme weather conditions can
interfere with our production and increase our costs and damage resulting from extreme weather may
not be fully insured. However, at this time we are unable to determine the extent to which climate
change may lead to increased storm or weather hazards affecting our operations.
We may face unanticipated water and other waste disposal costs.
We may be subject to regulation that restricts our ability to discharge water produced as part of
our gas production operations. Productive zones frequently contain water that must be removed in
order for the gas to produce, and our ability to remove and dispose of sufficient quantities of water
from the various zones will determine whether we can produce gas in commercial quantities. The
produced water currently is transported from the lease and injected into disposal wells. The availability
of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect
our ability to produce our wells. Also, the EPA expects to issue new standards regarding the disposal of
wastewater from hydraulic fracturing into publicly owned treatment facilities this year. Therefore, the
cost to transport and dispose of that water, including the cost of complying with regulations concerning
water disposal, may reduce our profitability.
In the event water produced from our projects fails to meet the quality requirements of applicable
regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the
disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to
secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have
to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The
costs to dispose of this produced water may increase if any of the following occur:
(cid:127) we cannot obtain future permits from applicable regulatory agencies;
(cid:127) water of lesser quality or requiring additional treatment is produced;
(cid:127) our wells produce excess water;
(cid:127) new laws and regulations require water to be disposed in a different manner; or
(cid:127) costs to transport the produced water to the disposal wells increase.
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 December 31,
2013, we had approximately $77 million of total available borrowing capacity under our revolving 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 $575 million available under our credit facilities would result in
increased annual interest expense of approximately $6.0 million and a corresponding decrease in our
net income. 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. 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.
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We conduct a substantial portion of our operations through farm-outs, areas of mutual interest and other joint
development agreements. These agreements subject us to additional risks that could have a material adverse
effect on the success of these operations, our financial position and our results of operations.
We conduct a substantial portion of our operations through joint development agreements with
third parties, including ExxonMobil and Vanguard Natural Resources. We may also enter into other
joint development agreements in the future. These third parties may have obligations that are
important to the success of the joint development agreement, such as the obligation to contribute
capital or pay carried or other costs associated with the joint development agreement. The performance
of these third party obligations, including the ability of the third parties to satisfy their obligations
under these arrangements, is outside our control. If these parties do not satisfy their obligations under
these arrangements, our business may be adversely affected.
Our joint development agreements may involve risks not otherwise present when exploring and
developing properties directly, including, for example:
(cid:127) our joint development partners may share certain approval rights over major decisions;
(cid:127) our joint development partners may not pay their share of the joint development agreement
obligations, leaving us liable for their share of joint development liabilities;
(cid:127) we may incur liabilities as a result of an action taken by our joint development partners;
(cid:127) our joint development partners may be in a position to take actions contrary to our instructions
or requests or contrary to our policies or objectives; and
(cid:127) disputes between us and our joint development partners may result in delays, litigation or
operational impasses.
The risks described above, the failure to continue our joint ventures or to resolve disagreements
with our joint development partners could adversely affect our ability to transact the business of such
joint development, which would in turn negatively affect our financial condition and results of
operations.
The Jones family and Metalmark Capital, our primary private equity investor, control a significant percentage
of Jones Energy, Inc.’s voting power and have the ability to take actions that may conflict with your interests.
As of December 31, 2013, the Jones family and Metalmark Capital held approximately 74.7% of
the combined voting power of Jones Energy, Inc. Although the Jones family and Metalmark Capital are
entitled to act separately in their own respective interests with respect to their ownership interests in
Jones Energy, Inc., the Jones family and Metalmark Capital will have the ability to elect all of the
members of our board of directors, and thereby control our management and affairs. In addition, the
Jones family and Metalmark Capital have significant influence over all matters that require approval by
our stockholders, including mergers and other material transactions.
The loss of senior management or technical personnel could adversely affect our operations.
Our success will depend to a large extent upon the efforts and abilities of our executive officers
and key operations personnel. The loss of the services of one or more of these key employees could
have a material adverse effect on us. We do not maintain insurance against the loss of any of these
individuals. Our business will also be dependent upon our ability to attract and retain qualified
personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more
than estimated. This could cause us to incur greater costs, or prevent us from pursuing our
development and exploitation strategy as quickly as we would otherwise wish to do.
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If we fail to develop or maintain an effective system of internal controls, we may not be able to report our
financial results accurately or prevent fraud.
We have had limited accounting personnel to execute our accounting processes and limited other
supervisory resources with which to address our internal control over financial reporting. As such, we
have not maintained an effective control environment to ensure that the design and execution of our
controls has consistently resulted in effective review of our financial statements and supervision by
appropriate individuals. As a result of these factors, certain material misstatements in our annual
financial statements were discovered and brought to the attention of our management by our
independent registered public accounting firm for correction. These material misstatements included
certain errors in our annual financial statements for the years ended 2010, 2011 and 2012, including
out-of-period adjustments and errors in the calculation of our depreciation, depletion and amortization
expense and our asset retirement obligations. We and our independent registered public accounting
firm concluded that these control deficiencies constituted a material weakness in our control
environment. A material weakness is a control deficiency, or a combination of control deficiencies, in
internal control over financial reporting, such that there is a reasonable possibility that a material
misstatement of our annual or interim financial statements will not be prevented or detected on a
timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the
material weakness in the control environment as further described below.
In 2010 and 2011, we did not maintain effective controls to ensure that correct inputs and formulas
in spreadsheets were used in our calculation of depreciation, depletion and amortization, or DD&A,
expense. In 2012, the lack of effective controls over last-minute journal entries and use of final adjusted
production data resulted in the misstatement of DD&A. For each of these periods, effective controls
were not adequately designed or consistently operating to ensure that key computations were properly
reviewed before the amounts were recorded in our accounting records. The above identified control
deficiencies resulted in audit adjustments to our consolidated financial statements during 2010, 2011,
and 2012.
In December 2012, we were notified by the Oklahoma Tax Commission that sales tax had not been
remitted on tangible property conveyed as part of the sale of a number of oil and gas properties.
Consequently, tax expense for periods prior to 2012 was understated. In 2013, we identified Oklahoma
regulations regarding the payment of interest on accrued royalties which had not been recorded. We
determined the amount of interest payable and recognized additional interest expense which was
incorporated into our Consolidated Statements of Operations, as revised. The lack of Oklahoma legal
and tax expertise on our staff led to these oversights. Management is reviewing the internal control
weakness related to these omissions to determine the proper organizational structure in response.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud
and to operate successfully as a publicly traded company. To comply with the requirements of being a
publicly traded company, we may need to implement additional financial and management controls,
reporting systems and procedures and hire additional accounting, finance, tax and legal staff. Our
efforts to develop and maintain our internal controls may not be successful, and we may be unable to
maintain effective controls over our financial processes and reporting in the future or to comply with
our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404.
For example, Section 404 will require us, among other things, to annually review and report on, and
our independent registered public accounting firm to attest to, the effectiveness of our internal controls
over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s
attestation report) beginning with our fiscal year ending December 31, 2014. Any failure to develop,
implement or maintain effective internal controls or to improve our internal controls could harm our
operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in
the design and operation of internal controls over financial reporting, we can provide no assurance as
to our conclusions about the effectiveness of our internal controls, and we may incur significant costs in
50
our efforts to comply with Section 404. If one or more material weaknesses persist or if we fail to
establish and maintain effective internal control over financial reporting, our ability to accurately report
our financial results could be adversely affected. Ineffective internal controls could also subject us to
regulatory scrutiny and a loss of confidence in our reported financial information, which could have an
adverse effect on our business.
For as long as we are an emerging growth company, we will not be required to comply with certain disclosure
requirements that apply to other public companies.
In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act (the
‘‘JOBS Act’’). For as long as we remain an ‘‘emerging growth company’’ as defined in the JOBS Act,
we may take advantage of certain exemptions from various reporting requirements that are applicable
to other public companies that are not emerging growth companies, including not being required to
provide an auditor’s attestation report on management’s assessment of the effectiveness of our system
of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and
reduced disclosure obligations regarding executive compensation in our periodic reports. We will
remain an emerging growth company for up to five years, although we will lose that status sooner if we
have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value
of our Class A common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible
debt over a three-year period.
To the extent that we rely on any of the exemptions available to emerging growth companies, you
will receive less information about our executive compensation and internal control over financial
reporting than issuers that are not emerging growth companies.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data
corruption, operational disruption or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct
certain exploration, development, production, processing and distribution activities. For example, we
depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment
and gathering and transportation systems, conduct reservoir modeling and reserves estimation and
process and record financial and operating data. As an oil and natural gas producer, we face various
security threats, including cyber-security threats. Cyber-security attacks in particular are increasing 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 to date we have
not experienced any material losses related to cyber-security attacks, we may suffer such losses in the
future. Moreover, the various procedures and controls we use to monitor and protect against these
threats and to mitigate our exposure to such threats may not 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.
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, possible consequences include our loss of communication links, inability to find, produce,
process and sell oil, natural gas and NGLs 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.
51
We will be required to make payments under the Tax Receivable Agreement for certain tax benefits it may
receive (or be deemed to receive), and the amounts of such payments could be significant.
We entered into the Tax Receivable Agreement with JEH LLC and the pre-IPO owners. This
agreement generally provides for the payment by us of 85% of the amount of cash savings, if any, in
U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to
realize in certain circumstances) as a result of (i) the tax basis increases resulting from the pre-IPO
owners’ exchange of JEH LLC Units with JONE for shares of Class A common stock (or resulting
from a sale of JEH LLC Units for cash) and (ii) imputed interest deemed to be paid by us as a result
of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.
In addition, payments we make under the Tax Receivable Agreement will be increased by any interest
accrued from the due date (without extensions) of the corresponding tax return.
The payment obligations under the Tax Receivable Agreement are our obligations and not
obligations of JEH LLC. For purposes of the Tax Receivable Agreement, cash savings in tax generally
are calculated by comparing our actual tax liability to the amount we would have been required to pay
had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The
term of the Tax Receivable Agreement will continue until all such tax benefits have been utilized or
expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the
termination payment specified in the agreement.
The actual increase in tax basis, as well as the amount and timing of any payments under the Tax
Receivable Agreement, will vary depending upon a number of factors, including the timing of the
exchanges of JEH LLC Units, the price of Class A common stock at the time of each exchange, the
extent to which such exchanges are taxable, the amount and timing of the taxable income we generate
in the future and the tax rate then applicable, and the portion of our payments under the Tax
Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We
expect that the payments that we will be required to make under the Tax Receivable Agreement could
be substantial.
The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights
under the Tax Receivable Agreement having a continued ownership interest in either JEH LLC or us.
In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed
the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.
If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to
certain mergers or other changes of control, we would be required to make an immediate payment
equal to the present value of the anticipated future tax benefits subject to the Tax Receivable
Agreement, which calculation of anticipated future tax benefits will be based upon certain assumptions
and deemed events set forth in the Tax Receivable Agreement, including the assumption that we have
sufficient taxable income to fully utilize such benefits and that any JEH LLC Units that the pre-IPO
Owners or their permitted transferees own on the termination date are deemed to be exchanged on the
termination date. Any early termination payment may be made significantly in advance of the actual
realization, if any, of such future benefits. In these situations, our obligations under the Tax Receivable
Agreement could have a substantial negative impact on our liquidity and could have the effect of
delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or
other changes of control due to the additional transaction cost a potential acquirer may attribute to
satisfying such obligations.
Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we
will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any
payments previously made under the Tax Receivable Agreement if such basis increases or other benefits
are subsequently disallowed, except that excess payments made to any pre-IPO Owner will be netted
52
against payments otherwise to be made, if any, to such pre-IPO owner after our determination of such
excess. As a result, in such circumstances, we could make payments that are greater than its actual cash
tax savings, if any, and may not be able to recoup those payments, which could adversely affect our
liquidity.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
Item 3. Legal Proceedings
We are from time to time subject to, and are presently involved in, litigation or other legal
proceedings arising out of the ordinary course of business. None of these legal proceedings are
expected to have a material adverse effect on our financial condition, results of operations or cash flow.
With respect to these proceedings, our management believes that we will either prevail, have adequate
insurance coverage or have established appropriate reserves to cover potential liabilities. Any costs that
management estimates may be paid related to these proceedings or claims are accrued when the
liability is considered probable and the amount can be reasonably estimated. There can be no
assurance, however, as to the ultimate outcome of any of these matters, and if all or substantially all of
these legal proceedings were to be determined adversely to us, there could be a material adverse effect
on our financial condition, results of operations and cash flow.
Items 4. Mine Safety Disclosures
Not applicable.
53
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Our common stock is listed on the New York Stock Exchange (‘‘NYSE’’) under the symbol
‘‘JONE.’’
The following table sets forth the range of high and low sales prices of our common stock as
reported by the NYSE for the third and fourth quarters of 2013:
2013
High
Low
3rd Quarter(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4th Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17.10
18.14
$13.60
13.15
(1) Represents the period from July 24, 2013, the date on which our common stock began
trading on the NYSE, through December 31, 2013.
On March 5, 2014, the last sale price of our common stock, as reported on the NYSE, was $15.04
per share. As of March 5, 2014, there were 12,526,580 shares of Class A common stock outstanding
held by approximately 6 stockholders of record and 36,836,333 shares of Class B common stock
outstanding held by approximately 11 stockholders of record.
Dividend Policy
We have not paid any dividends and do not anticipate declaring or paying any cash dividends to
holders of our Class A common stock in the foreseeable future. We currently intend to retain future
earnings, if any, to finance the growth of our business. Our future dividend policy is within the
discretion of our board of directors and will depend upon then existing conditions, including our results
of operations, financial condition, capital requirements, investment opportunities, statutory restrictions
on our ability to pay dividends and other factors our board of directors may deem relevant. In addition,
our senior secured revolving credit facility and our second lien term loan facility prohibit us from
paying dividends.
54
Stock Performance Graph
The following stock 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 of 1933, as amended (the ‘‘Securities Act’’), or the Securities
Exchange Act of 1934, as amended (the ‘‘Exchange Act’’), except to the extent that we specifically
incorporate such information by reference into such a filing. The graph and information is included for
historical comparative purposes only and should not be considered indicative of future stock
performance.
The graph compares the cumulative total shareholder return to Jones Energy, Inc.’s common
stockholders as compared to the cumulative total returns on the Standard & Poor’s 500 index (‘‘the
S&P 500 Index’’) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index
(‘‘S&P 500 O&G E&P Index’’) since the time of our IPO. The graph was prepared assuming $100 was
invested in our common stock at its initial public offering price of $15.00 per share and invested in the
S&P 500 Index and the S&P 500 O&G E&P Index on July 24, 2013 at the closing price on such date
and tracked through December 31, 2013.
$115
$110
$105
$100
$95
$90
$85
$80
24-Jul-13
31-Aug-13
30-Sep-13
31-Oct-13
30-Nov-13
31-Dec-13
JONE
S&P 500
S&P O&G E&P Index
11MAR201401095112
55
Securities Authorized for issuance Under Equity Compensation Plans
The following table presents the securities authorized for issuance under the Jones Energy, Inc.
2013 Omnibus Incentive Plan (the ‘‘LTIP’’) as of December 31, 2013.
Plan Category
Equity compensation plan approved
by security holders(1) . . . . . . . . . .
Equity compensation plans not
approved by security holders . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Total
Number of Shares to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights ($)
Number of Shares
Remaining Available for
Future Issuance under
Equity Compensation
Plans
—
—
—
—
—
—
3,823,420(2)
—
3,823,420
(1) Our 2013 Omnibus Incentive Plan (the ‘‘LTIP’’) was approved by our board of directors in July
2013 and took effect on July 29, 2013. The LTIP was also approved by our shareholders at the
Annual Meeting of Shareholders on July 10, 2013.
(2) The LTIP may consist of the following components: restricted stock, stock options, performance
awards, restricted stock units, bonus stock awards, stock appreciation rights, cash awards, dividend
equivalents, and other share-based awards. The LTIP limits the number of shares that may be
delivered pursuant to awards to 3,850,000 shares of our Class A common stock. On August 30,
2013, pursuant to the terms of the LTIP, our board of directors approved an award of 6,645 shares
of restricted Class A common stock to each of the four non-employee directors of JONE, or
26,580 shares of restricted stock in the aggregate.
Issuer Purchases of Equity Securities
None.
Sales of Unregistered Equity Securities
None.
Item 6. Selected Financial Data
The following table sets forth selected financial data of Jones Energy, Inc. and its predecessor for
the years ended December 31, 2013, 2012, 2011 and 2010. This information should be read in
connection with ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
56
Operations’’ and ‘‘Item 8. Financial Statements and Supplementary Data’’ presented elsewhere in this
report.
(in thousands except per share data)
Operating revenues
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2013
2012
2011
2010
$258,063
1,106
$148,967
847
$167,261
1,022
$ 97,523
933
Total operating revenues . . . . . . . . . . . . . . . . . . . .
259,169
149,814
168,283
98,456
Operating costs and expenses
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . . .
Accretion of discount
. . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative (including non-cash
27,781
12,865
1,710
114,136
14,415
608
23,097
5,583
356
80,709
18,821
533
21,548
5,333
780
68,906
31,970
413
compensation expense)
. . . . . . . . . . . . . . . . . . . . . . . .
31,902
15,875
16,679
Total operating expenses . . . . . . . . . . . . . . . . . . . .
203,417
144,974
145,629
Operating income . . . . . . . . . . . . . . . . . . . . . . . . .
55,752
4,840
22,654
16,296
2,206
4,208
48,008
10,727
490
11,423
93,358
5,098
Other income (expense)
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain (loss) on commodity derivatives . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . . . . . . . . . . . . . . . . . .
Gain (loss) on sales of assets . . . . . . . . . . . . . . . . . . . . . .
(30,774)
(2,566)
—
(78)
Other income (expense), net . . . . . . . . . . . . . . . . .
(33,418)
Income (loss) before income tax . . . . . . . . . . . . . .
22,334
(25,292)
16,684
—
1,162
(7,446)
(2,606)
(21,994)
34,490
26,208
(859)
37,845
60,499
(12,575)
23,758
—
8,644
19,827
24,925
Income tax provision
Current
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax provision . . . . . . . . . . . . . . . . . . .
85
(156)
(71)
—
473
473
—
173
173
—
145
145
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to non-controlling interests . . . . .
22,405
24,591
(3,079)
—
60,326
—
24,780
—
Net income (loss) attributable to controlling interests . . . .
$ (2,186) $ (3,079) $ 60,326
$ 24,780
Earnings per share:
Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(0.17)
Weighted average shares outstanding:
Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,500
Other Supplementary Data:
EBITDAX(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted net income(2) . . . . . . . . . . . . . . . . . . . . . . . .
$204,997
54,792
$135,741
29,411
$127,960
34,894
$ 74,771
17,599
(1) EBITDAX is a non-GAAP financial measure. For a definition of EBITDAX and a reconciliation
of EBITDAX to our net income, see ‘‘—Non-GAAP Financial Measures’’ below.
57
(2) Adjusted net income is a non-GAAP financial measure. For a definition of adjusted net income
and a reconciliation of adjusted net income to our net income, see ‘‘—Non-GAAP Financial
Measures’’ below.
Year Ended December 31,
(in thousands of dollars)
Statement of Cash Flow Data
Net cash flow provided by operating activities . . . . . $ 163,896 $ 84,550 $ 120,217 $ 44,624
(383,600) (337,636) (318,963) (90,785)
Net cash used in investing activities . . . . . . . . . . . . .
49,200
219,798
Net cash provided by financing activities . . . . . . . . .
270,676
186,322
2013
2012
2011
2010
Net increase (decrease) in cash . . . . . . . . . . . . . . . . $
94 $ 17,590 $ (12,424) $ 3,039
(in thousands of dollars)
Balance Sheet Data
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . $
Other current assets . . . . . . . . . . . . . . . . . . . . . . .
As of December 31,
2013
2012
2011
2010
23,820 $
106,459
23,726 $
74,886
6,136 $ 18,560
49,742
88,546
Total current assets . . . . . . . . . . . . . . . . . . . . . .
Property and equipment, net . . . . . . . . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . . . . . . . . .
130,279
1,315,995
41,705
98,612
1,010,742
41,332
94,682
743,575
42,878
68,302
495,613
21,379
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,487,979 $1,150,686 $881,135 $585,294
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . $ 179,668 $
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . .
Total stockholders’ / members’ equity . . . . . . . . . . .
658,000
26,187
624,124
93,421 $108,494 $ 60,938
225,000
415,000
610,000
14,907
11,733
18,865
284,449
345,908
428,400
Total liabilities and stockholders’ / members’
equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,487,979 $1,150,686 $881,135 $585,294
Non-GAAP financial measures
EBITDAX is a supplemental non-GAAP financial measure that is used by management and
external users of our consolidated financial statements, such as industry analysts, investors, lenders and
rating agencies.
We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion
and amortization, exploration expense, gains and losses from derivatives less the current period
settlements of matured derivative contracts and the other items described below. EBITDAX is not a
measure of net income as determined by United States generally accepted accounting principles, or
GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate
our operating performance and compare the results of our operations from period to period and
against our peers without regard to our financing methods or capital structure. We exclude the items
listed above from net income in arriving at EBITDAX because these amounts can vary substantially
from company to company within our industry depending upon accounting methods and book values of
assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations
as an analytical tool and should not be considered as an alternative to, or more meaningful than, net
income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items
excluded from EBITDAX are significant components in understanding and assessing a company’s
financial performance, such as a company’s cost of capital and tax structure, as well as the historical
costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference
that our results will be unaffected by unusual or non-recurring items. Our computations of EBITDAX
may not be comparable to other similarly titled measures of other companies.
58
The following table sets forth a reconciliation of net income (loss) as determined in accordance
with GAAP to EBITDAX for the periods indicated:
(in thousands of dollars)
Reconciliation of EBITDAX to net income
Year Ended December 31,
2013
2012
2011
2010
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense (excluding amortization of deferred
financing costs) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs . . . . . . . . . . . .
Depreciation and depletion . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and natural gas properties . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-cash charges . . . . . . . . . . . . . . . . . . . . . . . .
Stock compensation expense . . . . . . . . . . . . . . . . . . . . .
Other compensation expense . . . . . . . . . . . . . . . . . . . .
Net (gain) loss on derivative contracts . . . . . . . . . . . . . .
Current period settlements of matured derivative
contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred revenue . . . . . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . . . . . . . . . . . . . . . .
Loss (gain) on sales of assets . . . . . . . . . . . . . . . . . . . .
$ 22,405
$ (3,079) $ 60,326
$ 24,780
28,097
1,710
(71)
2,677
114,136
14,415
608
79
10,838
2,719
2,566
21,748
356
473
3,544
80,709
18,821
533
129
570
—
(16,684)
19,054
780
173
2,940
68,906
31,970
413
(59)
1,134
—
(34,490)
5,209
(469)
—
78
2,162
29,783
—
—
— (26,208)
859
(1,162)
10,610
4,208
145
1,965
48,008
10,727
490
390
—
—
(23,758)
5,850
—
—
(8,644)
EBITDAX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$204,997
$135,741
$127,960
$ 74,771
Adjusted Net Income and Adjusted Earnings per Share are supplemental non-GAAP financial
measures that are used by management and external users of the Company’s consolidated financial
statements.
We define Adjusted Net Income as net income excluding the impact of certain non-cash items
including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas
properties, non-cash compensation expense, and the gain on bargain purchase associated with the
Southridge acquisition in 2011. We define Adjusted Earnings per Share as earnings per share plus that
portion of the components of adjusted net income allocated to the controlling interests divided by
weighted average shares outstanding. We believe adjusted net income and adjusted earnings per share
are useful to investors because they provide readers with a more meaningful measure of our
profitability before recording certain items for which the timing or amount cannot be reasonably
determined. However, these measures are provided in addition to, not as an alternative for, and should
be read in conjunction with, the information contained in our financial statements prepared in
accordance with GAAP. Our computations of adjusted net income and adjusted earnings per share may
not be comparable to other similarly titled measures of other companies.
59
The following table provides a reconciliation of net income (loss) as determined in accordance
with GAAP to adjusted net income for the periods indicated.
(in thousands except per share data)
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (gain) loss on derivative contracts . . . . . . . . . . . . . .
Current period settlements of matured derivative
contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . .
Non-cash stock compensation expense . . . . . . . . . . . . . .
Other non-cash compensation expense . . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . . . . . . . . . . . . . . . . .
Tax impact(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2013
2012
2011
2010
$ 22,405
2,566
$ (3,079) $ 60,326
(34,490)
(16,684)
$ 24,780
(23,758)
5,209
14,415
10,838
2,719
—
(3,360)
2,162
29,783
31,970
18,821
1,134
570
—
—
— (26,208)
—
—
5,850
10,727
—
—
—
—
Adjusted net income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 54,792
$ 29,411
$ 34,894
$ 17,599
Adjusted net income attributable to non-controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(51,182)
Adjusted net income attributable to controlling interests . . .
$ 3,610
Earnings per share (basic and diluted) . . . . . . . . . . . . . . .
Net (gain) loss on derivative contracts . . . . . . . . . . . . . .
Current period settlements of matured derivative
contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . .
Non-cash stock compensation expense . . . . . . . . . . . . . .
Other non-cash compensation expense . . . . . . . . . . . . . .
Tax impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted earnings per share (basic and diluted) . . . . . . . . .
$
(0.17)
0.43
(0.01)
0.29
0.02
—
(0.27)
0.29
$
Effective tax rate on net income attributable to controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36.9%
(1) In arriving at adjusted net income, the tax impact of the adjustments to net income is determined
by applying the appropriate tax rate to each adjustment and then allocating the tax impact between
the controlling and non-controlling interests.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be
read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial
Statements appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains
‘‘forward-looking statements’’ that are based on management’s current expectations, estimates and
projections about our business and operations, and that involve risks and uncertainties. Our actual results
may differ materially from those currently anticipated and expressed in such forward-looking statements as a
result of a number of factors, including those we discuss under ‘‘Risk Factors,’’ ‘‘Cautionary Statement
Regarding Forward-Looking Statements’’ and elsewhere in this report.
Overview
Jones Energy, Inc. is an independent oil and gas company engaged in the exploration,
development, production and acquisition of oil and natural gas properties in the Anadarko and Arkoma
60
basins of Texas and Oklahoma. We have drilled over 645 total wells, including over 460 horizontal
wells, since our formation. We optimize returns through a disciplined emphasis on controlling costs and
promoting operational efficiencies, and we believe we are recognized as one of the lowest-cost drilling
and completion operators in the Cleveland and Woodford shale formations.
As of December 31, 2013, our total estimated proved reserves were 89.0 MMBoe, of which 56%
were classified as proved developed reserves. Approximately 19% of our total estimated proved
reserves as of December 31, 2013 consisted of oil, 37% consisted of NGLs, and 44% consisted of
natural gas.
Outlook
We have identified 2,542 additional gross drilling locations in our areas of operation for 2014 and
beyond, which we believe will enable us to drill and develop our resource base for many years. We
believe that the commodity pricing environment will remain challenging for 2014, particularly for
natural gas and NGLs. However, we believe that our drilling and completion cost efficiencies and our
existing drilling inventory position us to continue generating attractive economic rates of return and to
seek complementary acquisition and joint development opportunities.
Our 2013 capital expenditures, excluding acquisitions, totaled $240 million, during which we drilled
97 gross wells. We expect our 2014 capital expenditure budget to be approximately $350 million,
$310 million of which is expected to be used to drill and complete wells. The remainder of the 2014
capital expenditure budget is devoted to leasing and other discretionary expenditures. Please see
‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Liquidity and Capital Resources.’’ Assuming current market conditions and drilling success rates
comparable to our historical performance, we believe we will be able to fund all of our 2014 budgeted
capital expenditures with our cash flow from operations and projected availability under our senior
secured revolving credit facility.
We currently have ten rigs running in our two core areas, eight in the Cleveland and two in the
Woodford. We currently expect to allocate our 2014 capital expenditure budget as follows:
2014 Capital
Expenditure
Budget
(in millions)
Drilling and completion:
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Woodford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties and activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$250
50
10
20
20
$350
NGLs are made up of ethane, propane, isobutane, butane and natural gasoline, all of which have
different uses and different pricing characteristics. Realized monthly pricing for NGLs, which comprised
36% of our 2012 production and 28% of our 2013 production, has recently approached five-year lows,
principally due to oversupply in the market. Under our sale contracts in the Anadarko basin, we are
generally paid market rates for the NGLs we produce, so the lower pricing has resulted in lower NGL
revenues. However, under our sale contracts in the Arkoma Woodford, purchasers of NGLs have the
ability to bypass the separate purchase of ethane below specified price thresholds and to purchase the
ethane as part of a wet gas stream. Beginning in December 2012, purchasers have made this election
and are paying wet natural gas prices for the gas stream produced from our Arkoma Woodford
61
properties, which has resulted in increased natural gas production volumes and higher revenue from the
ethane as an incremental energy component of net natural gas than we would receive were it sold
separately at current prices. Although these elections can be made on a monthly basis and are entirely
outside of our control, we anticipate, based on current forward price curves, that these purchasers will
continue their elections to reject ethane and include it as part of the natural gas stream, which would
have the effect of increasing our natural gas production volumes and decreasing NGL production
volumes, in each case, by the amount of ethane rejected. Ethane constituted approximately 50% and
14% of our Woodford NGL production as of December 31, 2012 and December 31, 2013, respectively.
A further or extended decline in NGL prices, or in oil or natural gas prices, could materially and
adversely affect our financial position, our results of operations, the quantities of hydrocarbon reserves
that we can economically produce and our access to capital.
Basis of Presentation
We consider and report all of our operations as one segment.
Sources of our revenues
We derive our revenue from the production and sale of oil, natural gas and NGLs. Our revenues
are a function of oil, natural gas, and NGL production volumes sold and average sales prices received
for those volumes. We recognize revenues when the product is delivered at a fixed or determinable
price, title has transferred and collectability is reasonably assured and evidenced by a contract. Our
revenues do not include the effects of our hedging activities and may vary substantially from period to
period as a result of changes in production volumes or commodity prices.
Hedging
Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such
as collars, swaps and puts to hedge price risk associated with a significant portion of our anticipated oil,
natural gas and NGL production. These instruments allow us to reduce, but not eliminate, the potential
effects of variability in cash flow from operations due to fluctuations in commodity prices. The
instruments provide only partial price protection against declines in oil and gas prices, and may
partially limit our potential gains from future increases in prices. None of these instruments are used
for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical
production by individual hydrocarbon product in order to protect returns. The only counterparties to
our derivatives are current or former lenders under our senior secured revolving credit facility and
potential hedge positions are reviewed on a monthly basis. This eliminates potential margin calls in
execution and limits our credit exposure to these particular lenders. We have not designated any of our
derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are
included in net income. We record such derivative instruments as assets or liabilities in the statements
of financial position. During the year ended December 31, 2013, approximately 79% of our total
production for oil, natural gas and NGLs was hedged. As of December 31, 2013, approximately 35% of
our total forecasted production from proved reserves through 2018 was hedged, and the notional value
of our hedge position was over $680 million. We do not anticipate any substantial changes in our
hedging policy.
62
Our open positions as of December 31, 2013 were as follows:
Year Ending December 31,
2014
2015
2016
2017
2018
Oil positions(1):
Swaps:
Hedged volume (MBbl) . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Bbl) . . . . . . . . . . . . . . . . . . .
1,773
$ 91.12
1,271
$ 89.27
946
$87.49
625 —
$84.92 —
Natural gas positions(2):
Swaps:
Hedged volume (MMcf) . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Mcf) . . . . . . . . . . . . . . . . . .
13,940
4.87
$
10,663
4.89
$
8,450
$ 5.00
6,860 —
$ 4.50 —
NGL positions(3):
Swaps:
Hedged volume (MBbl) . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Bbl) . . . . . . . . . . . . . . . . . . .
1,273
$ 29.27
686
$ 32.05
238
$49.82
42 —
$64.39 —
Basis positions(4):
Swaps:
Hedged volume (MMcf) . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Mcf) . . . . . . . . . . . . . . . . . .
7,260
1,000
$ (0.35) $ (0.33) $ (0.28)
4,350
— —
— —
(1) The oil derivatives are settled based on the month’s average daily NYMEX price of West Texas
Intermediate Light Sweet Crude.
(2) The natural gas derivatives are settled based on the NYMEX gas futures price for the calculation
period.
(3) The NGL derivatives are settled based on the month’s average daily price of Mont Belvieu and
Conway ethane, propane, isobutane, butane and natural gasoline.
(4) The basis swap derivatives are settled based on the differential between the NYMEX gas futures
price and the ANR Pipeline Co. Oklahoma price, the CenterPoint Energy Gas Transmission Co.
east price, the Natural Gas Pipeline Co. of America Texok zone price, the Northern Natural
Gas Co. demarcation price or the Panhandle Eastern Pipe Line Co. Texas/Oklahoma price.
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 the market, together with the daily costs incurred to maintain our producing properties.
Such costs also include maintenance, repairs and workover expenses related to our oil and gas
properties. Lease operating expenses include both a portion of costs that are fixed in nature, such as
infrastructure costs, as well as variable costs resulting from additional well maintenance and production
enhancements. As production increases, our average lease operating expense per barrel of oil
equivalent is typically reduced because fixed costs do not increase proportionately with production.
Exploration. Exploration expense consists of geological and geophysical costs, seismic costs,
amortization of unproved leasehold costs, and the costs to drill exploratory wells that do not find
proved reserves.
Depreciation, depletion and amortization. Under the successful efforts accounting method that we
employ, we capitalize all costs associated with our acquisition, successful exploration, and all
development efforts within cost centers classified by producing field. We then systematically expense the
costs in each field on a units-of-production basis based on proved oil and natural gas reserve quantities.
63
We calculate depletion on (i) all capitalized costs, other than the cost of investments in unproved
properties and major development projects for which proved reserves cannot yet be assigned, less
accumulated amortization; and (ii) the estimated plugging 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 over the estimated useful lives.
Impairment of oil and gas properties. This is the cost to reduce the carrying value of each field of
proved and unproved oil and gas properties to no more than the fair value of the particular field.
Accretion of discount. Accretion of discounts are related to our obligation for retirement of oil
and gas wells and facilities. We record these liabilities when we place the assets in service, using
discounted present values of the estimated future obligation. We then record accretion of the liabilities
as they approach maturity.
General and administrative. These are costs incurred for overhead, including payroll and benefits
for our corporate staff, costs of maintaining our headquarters, costs of managing our production and
development operations, audit and other fees for professional services and legal compliance.
Interest and other. The primary component of this line item is the interest paid to lenders. We
finance a portion of our working capital requirements and capital expenditures with borrowings under
our senior secured revolving credit facility and our second lien term loan facility. As a result, we incur
interest expense that is affected by both fluctuations in interest rates and our financing decisions. This
classification also includes the amortization of capitalized loan acquisition costs and bank fees
associated with the debt and commitment fees on undrawn portions of our revolving credit facilities.
64
Results of Operations
The following table summarizes our revenues, expenses and production data for the periods
indicated.
(in thousands of dollars except for production,
sales price and average cost data)
Revenues:
Oil
. . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . .
NGLs . . . . . . . . . . . . . . . . . . . . . .
Total oil and gas . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
Years Ended December 31,
Years Ended December 31,
2013
2012
Change
2012
2011
Change
$145,146
55,511
57,406
258,063
1,106
$ 66,921
30,503
51,543
148,967
847
$ 78,225
25,008
5,863
109,096
259
$ 66,921
30,503
51,543
148,967
847
$ 73,769
39,983
53,509
167,261
1,022
$ (6,848)
(9,480)
(1,966)
(18,294)
(175)
Total operating revenues
. . . . .
259,169
149,814
109,355
149,814
168,283
(18,469)
Costs and expenses:
Lease operating . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . .
Depletion, depreciation and
amortization . . . . . . . . . . . . . . . .
Impairment of oil and gas properties
Accretion of discount . . . . . . . . . . .
General and administrative . . . . . . .
27,781
12,865
1,710
114,136
14,415
608
31,902
23,097
5,583
356
80,709
18,821
533
15,875
Total costs and expenses . . . . . .
203,417
144,974
Operating income . . . . . . . . . .
55,752
4,840
4,684
7,282
1,354
33,427
(4,406)
75
16,027
58,443
50,912
23,097
5,583
356
80,709
18,821
533
15,875
21,548
5,333
780
68,906
31,970
413
16,679
1,549
250
(424)
11,803
(13,149)
120
(804)
144,974
145,629
(655)
4,840
22,654
(17,814)
(30,774)
(25,292)
(5,482)
(25,292)
(21,994)
(3,298)
Other income (expenses):
Interest expense . . . . . . . . . . . . . . .
Net gain (loss) on commodity
derivatives . . . . . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . .
Gain (loss) on sales of assets . . . . . .
(2,566)
—
(78)
16,684
—
1,162
(19,250)
(1,240)
Total other income (expense) . .
(33,418)
(7,446)
(25,972)
Income before income tax . . . . . . . .
Income tax provision . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . .
Net income (loss) attributable to
22,334
(71)
22,405
(2,606)
473
24,940
(544)
(3,079)
25,484
16,684
—
1,162
(7,446)
(2,606)
473
(3,079)
34,490
26,208
(859)
37,845
60,499
173
60,326
(17,806)
(26,208)
2,021
(45,291)
(63,105)
300
(63,405)
non-controlling interests . . . . . . . . .
24,591
—
24,591
—
—
—
Net income (loss) attributable to
controlling interests . . . . . . . . . . . .
$ (2,186) $ (3,079) $
893
$ (3,079) $ 60,326
$(63,405)
65
Years Ended December 31,
Years Ended December 31,
2013
2012
Change
2012
2011
Change
Net production volumes:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . .
Total (MBoe) . . . . . . . . . . . . . . . . . . .
Average net (Boe/d) . . . . . . . . . . . . . .
1,557
17,575
1,724
6,210
17,014
746
14,066
1,773
4,863
13,287
811
3,509
(49)
1,347
3,727
746
14,066
1,773
4,863
13,287
811
11,443
1,215
3,933
10,775
(65)
2,623
558
930
2,512
Average sales price, unhedged:
Oil (per Bbl), unhedged . . . . . . . . . . . . .
Natural gas (per Mcf), unhedged . . . . . . .
NGLs (per Bbl), unhedged . . . . . . . . . . .
$ 93.22
3.16
33.30
$ 89.71
2.17
29.07
$ 3.51
0.99
4.23
$ 89.71
2.17
29.07
$ 90.96
3.49
44.04
$ (1.25)
(1.32)
(14.97)
Combined (per Boe) realized,
unhedged . . . . . . . . . . . . . . . . . . . .
41.56
30.63
10.93
30.63
42.53
(11.90)
Average sales price, hedged:
Oil (per Bbl), hedged . . . . . . . . . . . . . . .
Natural gas (per Mcf), hedged . . . . . . . .
NGLs (per Bbl), hedged . . . . . . . . . . . . .
Combined (per Boe) realized, hedged .
$ 87.86
3.93
33.26
42.40
$ 87.30
3.76
34.22
36.76
$ 0.56
0.17
(0.96)
5.64
$ 87.30
3.76
34.22
36.76
$ 99.02
2.48
46.41
41.98
$(11.72)
1.28
(12.19)
(5.22)
Average costs (per BOE):
Lease operating . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization .
General and administrative . . . . . . . . . . .
$
4.47
2.07
18.38
5.14
$
4.75
1.15
16.60
3.26
$ (0.28) $
0.92
1.78
1.88
4.75
1.15
16.60
3.26
$
5.48
1.36
17.52
4.24
$ (0.73)
(0.21)
(0.92)
(0.98)
Results of Operations—Year ended December 31, 2013 as compared to year ended December 31, 2012
Operating revenues
Oil and gas sales. Oil and gas sales increased by $109.1 million (73.2%) to $258.1 million for the
year ended December 31, 2013, as compared to $149.0 million for the year ended December 31, 2012.
The majority of the increase (69.3%) was due to higher crude oil production volumes with the
remainder of the increase being attributable to higher natural gas production volumes combined with
higher prices for all products. Average daily production increased 28.0% to 17,014 Boe per day for the
year ended December 31, 2013 as compared to 13,287 Boe per day for the year ended December 31,
2012. Crude oil production increased 108.7% from 746 MBbls for the year ended December 31, 2012
to 1,557 MBbls for the year ended December 31, 2013, primarily resulting from the wells acquired from
Chalker, which generally have an oil production rate that is higher than our average historical
Cleveland wells, combined with an increase in the number of wells drilled in 2013. Natural gas
production increased 24.9% from 14,066 MMcf for the year ended December 31, 2012 to 17,575 MMcf
for the year ended December 31, 2013, due to new wells added through drilling and the Chalker
acquisition. The average realized oil price, excluding the effects of commodity derivative instruments,
increased from $89.71 per Bbl to $93.22 per Bbl, or 3.9%, year over year. The average realized natural
gas price, excluding the effects of commodity derivative instruments, increased from $2.17 per Mcf to
$3.16 per Mcf, or 45.6%, year over year. The average realized natural gas liquids price, excluding the
effects of commodity derivative instruments, increased from $29.07 per Bbl to $33.30 per Bbl, or 14.6%.
Costs and expenses
Lease operating. Lease operating expense increased by $4.7 million (20.3%) to $27.8 million for
the year ended December 31, 2013, as compared to $23.1 million for the year ended December 31,
66
2012. The increase occurred in correlation with the 28.0% increase in production volumes. On a per
unit basis, lease operating expense decreased by $0.28 per Boe or 5.9%, from $4.75 to $4.47 per Boe,
for the year ended December 31, 2013 as compared to the year ended December 31, 2012. On an
overall basis, lease operating expense increased due to new wells coming on line and higher compressor
and salt water disposal expenses associated with the Chalker wells (as compared to our historical set of
wells); however, on a per unit basis, lease operating expense decreased as the Chalker properties have
an initial production rate that is higher than our average historical Cleveland well.
Production taxes. Production taxes increased by $7.3 million (130.4%) to $12.9 million for the year
ended December 31, 2013, as compared to $5.6 million for the year ended December 31, 2012. Overall
production taxes increased in conjunction with the 73.2% increase in revenue; however, the average
effective rate increased from 3.7% for the year ended December 31, 2012 to 5.0% for the year ended
December 31, 2013. Production taxes were at a higher rate during 2013 due to the acquisition and
drilling of the Chalker properties in Texas, which imposes a higher initial tax rate (7.5%) than
Oklahoma (1%), where many of our other properties are located.
Exploration. Exploration expense increased from $0.4 million for the year ended December 31,
2012 to $1.7 million for the year ended December 31, 2013. The increase was related to seismic
expenses incurred in the Arkoma.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by
$33.4 million (41.4%) to $114.1 million for the year ended December 31, 2013, as compared to
$80.7 million for the year ended December 31, 2012. The increase was primarily the result of continued
drilling activity and the acquisition of the Chalker properties at the end of 2012. On a per unit basis,
depletion expense increased $1.78 per Boe or 10.7% from $16.60 per Boe for the year ended
December 31, 2012 as compared to $18.38 per Boe for the year ended December 31, 2013. The per
unit increase resulted from the acquisition of the Chalker and Sabine properties, the write off of
proved undeveloped reserves attributable to the Southridge joint development agreement, and the
higher cost to drill wells in 2013 compared to historical wells. The write-off of the Southridge reserves
will increase depletion expense per Boe, provided all other inputs are constant.
Impairment of oil and gas properties. We had impairment charges on oil and gas properties of
$14.4 million for the year ended December 31, 2013 as compared to impairment charges of
$18.8 million for the year ended December 31, 2012. In the fourth quarter of 2013, the Company
recorded an impairment charge of $14.4 million related to its unproved Southridge properties. As the
Company did not drill the required number of wells by October 31, 2013 necessary to keep its joint
development agreement with Southridge in effect, the Company lost its right to drill the undeveloped
acreage and associated unproved reserves. In 2012, all of the impairment charges related to inactive
fields and minor plays, where the Company did not have any development. None of the 2013 charges
were in the Cleveland formation.
General and administrative. General and administrative expenses increased by $16.0 million
(100.6%) to $31.9 million for the year ended December 31, 2013, as compared to $15.9 million for the
year ended December 31, 2012. Of this increase, $10.8 million related to stock compensation expense
(of which $9.6 million was related to the immediate vesting of certain shares on the IPO date) and
$2.7 million related to a one-time non-cash distribution to management related to the Monarch
incentive plan. 2012 includes $0.6 million of stock compensation expense. Excluding these non-cash
items, general and administrative expenses increased $3.0 million (19.6%) to $18.3 million for the year
ended December 31, 2013, as compared to $15.3 million for the year ended December 31, 2012. The
increase in cash general and administrative expense is attributable to an increase in salaries and
benefits due to an increase in headcount to support our increased drilling activity, which was partially
offset by an increase in overhead reimbursements, and an increase in professional fees incurred as a
result of being a public company for a portion of 2013. On a per unit basis, cash general and
67
administrative expenses decreased from $3.15 per Boe for the year ended December 31, 2012 to
$2.95 per Boe for the year ended December 31, 2013. The increase in activity resulting from drilling
and the acquisition of the Chalker properties significantly increased production (28.0% on a Boe basis)
but did not result in a proportional increase in general and administrative expenses.
Interest and other.
Interest and other financing expenses increased by $5.5 million (21.7%) to
$30.8 million for the year ended December 31, 2013, as compared to $25.3 million for the year ended
December 31, 2012. Of the total expense, interest paid under our bank debt totaled $26.3 million and
$20.6 million for the years ended December 31, 2013 and 2012, respectively. We increased our debt at
the end of 2012 to fund the Chalker acquisition. In July 2013, a majority of this was paid down with
the proceeds from the initial public offering. At the end of 2013, we increased our debt again to fund
the Sabine acquisition. Our average debt outstanding for the year ended December 31, 2013 was
$544.9 million as compared to $428.1 million for the year ended December 31, 2012 and the weighted
average interest rate incurred on the outstanding borrowings was 4.82% and 4.96%, respectively.
Gain (loss) on commodity derivatives. We had a net loss on commodity derivatives of $2.6 million
for the year ended December 31, 2013 as compared to a net gain of $16.7 million for the year ended
December 31, 2012. The decrease is attributable to increases in crude oil and natural gas prices year
over year (crude oil prices averaged $97.97 during 2013 as compared to $94.20 during 2012 and natural
gas prices averaged $3.65 in 2013 as compared to $2.79 in 2012) combined with increases in future
crude oil prices from 2012 to 2013 as compared to decreases in future crude oil prices from 2011 to
2012. The 12-month forward prices at December 31, 2013 for crude oil averaged $95.66 per Bbl as
compared to $93.09 per Bbl at December 31, 2012, while the 12-month forward prices at December 31,
2012 averaged $93.09 per Bbl as compared to $98.77 per Bbl at December 31, 2011.
Gain (loss) on sales of assets. The gain on sales of assets decreased from $1.2 million for the year
ended December 31, 2012 to a loss of $0.1 million for the year ended December 31, 2013, due to the
sale of properties in the North Barnett Shale during the first quarter of 2012 compared with no
significant sales of properties in 2013.
Income taxes. The provision for income taxes calculated for 2013 reflects our reorganization and
recapitalization which occurred in connection with the Company’s initial public offering. Following the
IPO, the Company is subject to federal and state income and franchise taxes, while only the Texas
franchise tax applied to JEH LLC prior to the IPO. The income tax expense decreased from
$0.5 million for the year ended December 31, 2012 to a benefit of $0.1 million for the year ended
December 31, 2013. The 2012 income tax expense solely reflected the Texas franchise tax liability for
JEH LLC. The 2013 income tax benefit included a benefit for federal income taxes reduced by the
Texas franchise tax expense. The non-controlling interest was allocated its proportionate share of the
Texas franchise tax expense incurred during 2013.
Results of Operations—Year ended December 31, 2012 as compared to year ended December 31, 2011
Operating Revenues
Oil and gas sales. Our oil and gas sales decreased by $18.3 million (10.9%) to $149.0 million
during the year ended December 31, 2012, as compared to $167.3 million for the year ended
December 31, 2011. The revenue decrease was primarily due to lower commodity prices for natural gas
and NGLs and lower oil production volumes. Realized average natural gas prices, without derivatives,
decreased 37.8% during the year, falling to $2.17 per Mcf in 2012 from $3.49 per Mcf in 2011. Realized
average NGL prices, without derivatives, decreased 34.0%, falling to $29.07 per Bbl in 2012 from
$44.04 per Bbl in 2011. Oil production declined to 746 MBbls in 2012 from 811 MBbls, a decrease of
8.0%, as we pursued more wet gas prospects in 2012, increasing natural gas and NGL production by
22.9% and 45.9%, respectively.
68
Costs and Expenses
Lease operating. Our lease operating expense increased by approximately $1.6 million (7.4%) to
$23.1 million during the year ended December 31, 2012, as compared to $21.5 million for the year
ended December 31, 2011. This increase was primarily due to an increase in the number of operated
wells due to continued drilling activity. On a per unit basis, lease operating expense decreased
$0.73 per Boe to $4.75 per Boe in 2012 from $5.48 per Boe in 2011, due to the emphasis on drilling
liquids-rich prospects, which increased the overall productivity of our properties, as the increase in the
production of natural gas and NGLs offset the decline in oil production.
Production taxes. Our production taxes increased by $0.3 million to $5.6 million (5.7%) during the
year ended December 31, 2012, as compared to $5.3 million during the year ended December 31, 2011.
Although total revenues decreased, the increase in production tax expense was primarily due to an
increase in the backlog of wells at the Railroad Commission of Texas, or TRRC, waiting for approval of
tax rate reductions. We currently estimate that we have approximately $1.9 million in pending tax
reductions with the TRRC.
Exploration. Exploration expenses decreased by $0.4 million to $0.4 million (50.0%) during the
year ended December 31, 2012, as compared to the $0.8 million during the year ended December 31,
2011. The decrease was primarily due to no dry hole cost charged to expense in 2012.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by
$11.8 million to $80.7 million (17.1%) for the year ended December 31, 2012, as compared to
$68.9 million for the year ended December 31, 2011. This was primarily a result of an increase in
production and continued drilling activity. On a per unit basis, depletion expense decreased to
$16.60 per Boe for 2012, compared to $17.52 per Boe for 2011 as overall production increased.
Impairment of oil and gas properties. Our impairment of oil and gas properties decreased by
$13.2 million to $18.8 million for the year ended December 31, 2012, as compared to $32.0 million for
the year ended December 31, 2011. Our impairment charges relate to inactive fields and minor plays,
which we are not currently developing. None of these charges were in the Cleveland or Woodford shale
formations. In 2011, impairment charges related to these fields, along with a number of sales of minor
properties, significantly reduced the remaining carrying values of these fields, thereby reducing further
impairment.
General and administrative. Our general and administrative expenses decreased by $0.8 million to
$15.9 million (4.8%) during the year ended December 31, 2012, as compared to $16.7 million during
the year ended December 31, 2011. The decrease was attributable to decreases in stock compensation
expenses and legal expenses in 2012 versus 2011, partially offset by an increase in staff. On a per unit
basis, general and administrative expense decreased in 2012 to $3.26 per Boe from $4.24 per Boe, due
to an increase in production without a commensurate rise in expense.
Interest and other. Our interest and other financing expenses increased by $3.3 million to
$25.3 million (15.0%) during the year ended December 31, 2012, as compared to $22.0 million during
the year ended December 31, 2011, primarily due to an $81.9 million increase in average outstanding
debt for 2012 as compared to the prior year. The increase in average outstanding debt was primarily
used to finance the Chalker acquisition and continued drilling activity.
Gain on commodity derivatives. Our net gain on commodity derivatives decreased by $17.8 million
to $16.7 million during the year ended December 31, 2012, as compared to $34.5 million during the
year ended December 31, 2011. The 2012 results include gains attributable to a drop in crude oil
prices, compounded by an increase in oil production volumes hedged. The 12-month forward prices at
December 31, 2012 for crude oil averaged $93.22 per Bbl, while the 12-month forward prices at
December 31, 2011 averaged $98.77 per Bbl. These gains were reduced by higher gas prices, year over
69
year. The 12-month forward prices at December 31, 2012 for natural gas averaged $3.54 per MMBtu,
while the 12-month forward prices at December 31, 2011 averaged $3.25 per MMBtu. The 2011 net
gain was primarily attributable to a decrease in natural gas prices. The 12-month forward prices at
December 31, 2011 for natural gas averaged $3.25 per MMBtu, while the 12-month forward prices at
December 31, 2010 averaged $4.55 per MMBtu.
Gain (loss) on sales of assets. Our gain (loss) on sales of assets increased from a loss of
$0.9 million during the year ended December 31, 2011 to a gain of $1.2 million during the year ended
December 31, 2012, primarily due to the sale in 2012 of properties in the North Barnett Shale at a gain
compared to less significant sales of properties in 2011.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been private and public sales of our equity,
borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has
been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves
and production growth, we continually consider which capital resources, including equity and debt
financings, are available to meet our future financial obligations, planned capital expenditure activities
and liquidity requirements. Our future ability to grow proved reserves and production will be highly
dependent on the capital resources available to us. We strive to maintain financial flexibility in order to
maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate
drilling on our undeveloped acreage positions and permit us to selectively expand our acreage
positions. Depending on the timing and concentration of the development of our non-proved locations,
we may be required to generate or raise significant amounts of capital to develop all of our potential
drilling locations should we endeavor to do so. In the event our cash flows are materially less than
anticipated and other sources of capital we historically have utilized are not available on acceptable
terms, we may curtail our capital spending. Our balance sheet at December 31, 2013 reflects a working
capital deficit as we use the available balance of the borrowing base under our senior secured revolving
credit facility to manage cash flow. The available borrowing base of $77.0 million exceeds the working
capital deficit of $49.4 million.
Our 2014 capital budget will be primarily focused on the development of existing core areas in the
Cleveland and Woodford plays through exploitation and development. The ultimate amount of capital
we will expend may fluctuate materially based on market conditions, the economic returns being
realized and the success of our drilling results as the year progresses. We expect to fund our entire
2014 capital budget with cash flows from operations and borrowings under our senior secured revolving
credit facility. If necessary, we may also access capital through proceeds from potential asset
dispositions and the future issuance of debt and/or equity securities.
The amount, timing and allocation of capital expenditures are largely discretionary and within
management’s control. If oil and gas prices decline to levels below our acceptable levels, or costs
increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted
capital expenditures until later periods in order to achieve the desired balance between sources and
uses of liquidity and prioritize capital projects that we believe have the highest expected returns and
potential to generate near-term cash flow. We may also increase our capital expenditures significantly
to take advantage of opportunities we consider to be attractive. Because leases covering less than 3%
of our core property acreage are set to expire through December 31, 2014, and all but 50 PUD
locations currently are held by production, we have the ability to materially decrease our drilling and
recompletion budget in response to market conditions with low risk of losing significant acreage. We
consistently monitor and adjust our projected capital expenditures in response to success or lack of
success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs,
industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations,
internally generated cash flow and other factors both within and outside our control.
70
The following table summarizes our cash flows for the years ended December 31, 2011, 2012 and
2013:
Year Ended December 31,
2013
2012
2011
Net cash provided by operating activities . . . . . .
Net cash used in investing activities . . . . . . . . . .
Net cash provided by financing activities . . . . . .
$ 163,896
(383,600)
219,798
(in thousands)
$ 84,550
(337,636)
270,676
$ 120,217
(318,963)
186,322
Net increase (decrease) in cash . . . . . . . . . . . . .
$
94
$ 17,590
$ (12,424)
Cash Flow Provided by Operating Activities
Net cash provided by operating activities was $163.9 million for the year ended December 31, 2013
as compared to cash provided by operating activities of $84.6 million for the year ended December 31,
2012. The increase in operating cash flows was primarily due to a $109.1 million increase in oil and gas
revenues for the year ended December 31, 2013 as compared to the year ended December 31, 2012.
The increase in revenue was primarily driven by a 108.7% increase in oil production volumes as a
result of drilling and the Chalker acquisition in the fourth quarter of 2012, combined with increases in
crude oil and natural gas prices and other volumes. The increase in cash flow was offset by increased
capital spending resulting from an increase in drilling activity from four rigs running at December 31,
2012 to ten rigs running at December 31, 2013.
Net cash provided by operating activities was $84.6 million for the year ended December 31, 2012
as compared to cash provided by operations of $120.2 million for the year ended December 31, 2011.
The decrease in operating cash flows in 2012 compared to 2011 was primarily due to the decrease of
$18.3 million in revenues year over year on relatively flat operating expenses. While production
increased, the 37.8% drop in realized average natural gas prices and the 34.0% decline in realized
average NGL prices primarily drove the decrease in revenues. The reduction in net cash provided by
operating activities also stemmed from changes in working capital. Receivables from joint interest
owners declined $13.1 million due to the Company retaining a higher working interest ownership in
wells being drilled and a reduction in the number of active drilling rigs. In addition, oil and gas sales
payable decreased $8.4 million.
Our operating cash flows are sensitive to a number of variables, the most significant of which is
the volatility of oil and gas 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 Flow Used in Investing Activities
Net cash used in investing activities was $383.6 million for the year ended December 31, 2013 as
compared to cash used in investing activities of $337.6 million for the year ended December 31, 2012.
The increase was primarily driven by higher capital expenditures which increased $117.5 million during
the year ended December 31, 2013 as compared to the year ended December 31, 2012 due to an
increase in drilling activity. The increase in capital expenditures was partially offset by the decrease in
acquisitions as the purchase price of the Sabine acquisition ($193.5 million) at the end of 2013 was less
than that of the Chalker acquisition ($253.5 million) at the end of 2012. Additionally, cash flows from
current period settlements of our commodity derivatives instruments decreased by $21.1 million for the
year ended December 31, 2013 as compared to the year ended December 31, 2012 as a result of an
increase in crude oil and natural gas prices. Finally, we received cash proceeds of $9.2 million from the
sale of North Barnett properties in the first quarter of 2012, and experienced no meaningful sales of
properties occurring during the year ended December 31, 2013.
71
We had net cash used in investing activities of $337.6 million for the year ended December 31,
2012 as compared to cash used in investing of $319.0 million for the year ended December 31, 2011.
The increase in cash used in investing activities was primarily related to the Chalker acquisition in 2012
which was larger than the Southridge acquisition in 2011. This incremental acquisition investment was
partially offset by a decline in net drilling and equipment expenditures and an increase in gains realized
through commodity derivatives in 2012.
We expect our 2014 capital expenditures to be approximately $350 million, which is a 46% increase
over the $240 million incurred for 2013. Expenditures for development and exploration of oil and gas
properties are the primary use of our capital resources. Our capital budget may be adjusted as business
conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary
and within our control. If oil and natural gas prices decline or costs increase significantly, we could
defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital
projects that we believe have the highest expected returns and potential to generate near-term cash
flows. We routinely monitor and adjust our capital expenditures in response to changes in prices,
availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory
approvals, the availability of rigs, the degree of success in drilling activities, contractual obligations,
internally generated cash flows and other factors both within and outside our control.
Cash Flow Provided by Financing Activities
Net cash provided by financing activities was $219.8 million for the year ended December 31, 2013
as compared to net cash provided by financing activities of $270.7 million for the year ended
December 31, 2012. The decrease in cash flows provided by financing activities was primarily due to net
borrowings of $47.3 million during 2013 as compared to $185.7 million during 2012. The net proceeds
from the initial public offering of our Class A common stock of $172.5 million (net of expenses) in the
third quarter of 2013 were used to repay debt of $167.0 million during the year ended December 31,
2013.
Net cash provided by financing activities was $270.7 million during the year ended December 31,
2012 as compared to cash provided by financing of $186.3 million during the year ended December 31,
2011. The increase in cash flows provided by financing activities was primarily due to an $85.0 million
contribution of new equity capital by our existing owners for preferred units. Borrowings under our
credit facility, net of repayments, remained relatively unchanged at $185.7 million in 2012 and
$186.3 million in 2011.
Credit Facilities
Senior Secured Revolving Credit Facility.
JEH LLC has a $1 billion senior secured revolving credit
facility with Wells Fargo Bank, N.A. as the administrative agent, and a syndicate of lenders. Availability
under the senior secured revolving credit facility is subject to a borrowing base, which is currently
$575 million. The senior secured revolving credit facility matures in November 2017. As of
December 31, 2013, JEH LLC had borrowings of $498 million outstanding under the senior secured
revolving credit facility. JEH LLC’s obligations under the senior secured revolving credit facility are
guaranteed by Jones Energy, Inc. and JEH LLC’s domestic subsidiaries and are secured by substantially
all of its and their assets (other than equity interests of JEH LLC held by Jones Energy, Inc.).
The borrowing base under our senior secured revolving credit facility was redetermined by the
lenders on December 18, 2013, which was deemed to be the redetermination scheduled for August 1,
2013, and will be redetermined on April 1, 2014 and semi-annually thereafter on February 1 and
August 1 of each year. JEH LLC and the administrative agent (acting at the direction of lenders
holding at least 662⁄3% of the outstanding loans and letter of credit obligations) may each request one
unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the
72
lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our
material operating agreements or upon the cancellation or termination of certain of our joint
development agreements. The borrowing base will also be reduced in certain circumstances as a result
of our issuance of unsecured notes by an amount equal to 25% of the principal amount of unsecured
notes issued in excess of $400 million, our termination of certain hedging positions and our
consummation of certain asset sales.
If the aggregate outstanding principal amount of the revolving loans under the senior secured
revolving credit facility exceeds the borrowing base as a result of a scheduled or interim adjustment of
the borrowing base, we must prepay revolving loans in an amount equal to such excess and, if necessary
to eliminate such excess, cash collateralize outstanding letters of credit within 90 days following the
date the adjustment occurs or the date we receive notice thereof (with at least one-half of the
prepayment to be paid or deposited within 45 days following such date). However, if such a borrowing
base deficiency results from a permitted disposition of oil and gas properties, we must make such
prepayment and/or deposit of cash collateral on the date we receive cash proceeds as a result of such
disposition, and if such a borrowing base deficiency results from certain terminations or modifications
of hedge positions, we must immediately make such prepayment and/or deposit of cash collateral.
Otherwise, all unpaid principal and interest is due at maturity.
On January 29, 2014, JEH LLC entered into an Eighth Amendment (the ‘‘Eighth Amendment’’) to
the senior secured revolving credit facility. The Eighth Amendment amends the senior secured
revolving credit facility to, among other things, (1) reduce the commitment fee and interest rate margin
applicable to loans under the senior secured revolving credit facility, (2) increase the basket available
for issuance of senior unsecured notes from $300 million to $500 million, (3) provide additional
flexibility with respect to entrance into derivative arrangements in anticipation of acquisitions of oil and
gas properties and (4) provide for a guarantee of JEH LLC’s obligations under the senior secured
revolving credit facility by Jones Energy, Inc. The foregoing description of the Eighth Amendment is
not complete and is qualified by reference to the complete document, which is attached hereto as
Exhibit 10.20 and is incorporated herein by reference.
Interest on loans under our senior secured revolving credit facility is calculated at a base rate
(being at JEH LLC’s option, either (i) the per annum rate appearing on Reuters Screen LIBOR01
Page, or the LIBO Rate, for the applicable interest period or (ii) the greatest of (x) the prime rate
announced by Wells Fargo Bank, N.A., (y) the federal funds rate plus 0.50% and (z) the one-month
adjusted LIBO Rate plus 1.00%, plus a margin ranging from 0.50% to 2.50% based on the actual
amount borrowed compared to the borrowing amount and the base rate selected. JEH LLC is also
required to pay a quarterly commitment fee on the unused portion of the aggregate commitments of
the lenders, at a rate per annum of either 0.375% or 0.50%, depending on our utilization of the
borrowing base.
The senior secured revolving credit facility contains various covenants that, among other things,
limit our ability to:
(cid:127) incur indebtedness;
(cid:127) grant liens on our assets;
(cid:127) pay dividends or distributions or redeem any of our equity interests, or prepay any of the second
lien term loans (with an exception allowing us to repay the second lien term loans from the
proceeds of the issuance of senior unsecured notes);
(cid:127) make certain investments, loans and advances;
(cid:127) merge into or with or consolidate with any other person, or dispose of all or substantially all of
our property to any other person;
73
(cid:127) engage in certain asset dispositions;
(cid:127) enter into transactions with affiliates;
(cid:127) grant negative pledges or agree to restrict dividends or distributions from subsidiaries;
(cid:127) allow gas imbalances, take-or-pay or certain other prepayments with respect to oil and gas
properties; and
(cid:127) enter into certain derivative arrangements.
The senior secured revolving credit facility also contains a covenant which restricts the ability of Jones
Energy, Inc. to (i) hold any assets, (ii) incur, create, assume, or suffer to exist any debt or any other
liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any other activity
or operation other than, among other exceptions described therein, its ownership of equity interests in
JEH LLC and the activities of a passive holding company and assets and operations incidental thereto
(including the maintenance of cash and reserves for the payment of taxes, franchises, and other
operational costs and expenses).
Jones Energy, Inc. and its consolidated subsidiaries are also required under the senior secured
revolving credit facility to maintain the following financial ratios:
(cid:127) a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to
1.00 as of the last day of any fiscal quarter; and
(cid:127) a current ratio, consisting of consolidated current assets, including the unused amounts of the
total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last
day of any fiscal quarter.
We believe that we are in compliance with the terms of our senior secured revolving credit facility.
If an event of default exists under the credit agreement, the lenders will be able to accelerate the
obligations outstanding under the credit agreement and exercise other rights and remedies. Our senior
secured revolving credit facility contains customary events of default, including a change of control, as
defined in the senior secured revolving credit facility.
Second Lien Term Loan Facility.
In addition, JEH LLC has a $160 million second lien term loan
facility with Wells Fargo Energy Capital, Inc., as the administrative agent, and a syndicate of lenders.
The second lien term loan facility matures in May 2018. JEH LLC currently has $160 million in loans
outstanding under the second lien facility. An intercreditor agreement governs the relationship between
the lenders under the senior secured revolving credit facility and the lenders under the second lien
term loan facility.
The principal amount of the loans borrowed under the second lien term loan facility is due in full
on the maturity date. Interest on our second lien term loan facility is calculated at a base rate (being,
at JEH LLC’s option, either (i) the LIBO Rate for the applicable interest period (but in any event not
less than 2.00%) or (ii) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A.,
(y) the federal funds rate plus 0.50% and (z) the one-month adjusted LIBO Rate plus 1.00%, plus a
margin of either 6.0% or 7.0% based on the base rate selected.
Our second lien term loan facility contains various restrictive covenants that are similar to those in
our senior secured revolving credit facility.
Off-Balance Sheet Arrangements
At December 31, 2013, we did not have any off-balance sheet arrangements.
74
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2013:
Payments Due by Period
Total
Less than
1 Year
1 - 3 Years
4 - 5 Years
Thereafter
Long-term debt obligations . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . .
Drilling rig commitments . . . . . . . . . . . . . . . . .
Commodity derivative obligations . . . . . . . . . . .
Operating lease obligations . . . . . . . . . . . . . . .
Asset retirement obligations, discounted . . . . . .
$658,000
121,556
19,727
10,855
1,637
10,963
(dollars in thousands)
$ — $498,000
86,774
—
190
1,051
812
29,691
19,727
10,665
586
2,590
$160,000
5,090
—
—
—
493
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$799,283
$63,259
$586,827
$165,583
$ —
—
—
—
—
7,068
$7,068
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting principles
generally accepted in the United States, or GAAP. As used herein, the following acronyms have the
following meanings: ‘‘FASB’’ means the Financial Accounting Standards Board; the ‘‘Codification’’
refers to the Accounting Standards Codification, the collected accounting and reporting guidance
maintained by the FASB; ‘‘ASC’’ means Accounting Standards Codification and is generally followed by
a number indicating a particular section of the Codification; and ‘‘ASU’’ means Accounting Standards
Update, followed by an identification number, which are the periodic updates made to the Codification
by the FASB.
The preparation of our consolidated financial statements requires us to make estimates and
assumptions that affect our reported results of operations and the amount of reported assets, liabilities
and proved oil and natural gas reserves. Some 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. Actual results may differ
from the estimates and assumptions used in the preparation of our consolidated financial statements.
Described below are the most significant policies we apply in preparing our consolidated financial
statements, some of which are subject to alternative treatments under GAAP. We also describe the
most significant estimates and assumptions we make in applying these policies.
Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP
requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial
statements and the amounts of revenues and expenses reported for the period then ended.
Reserves. Reserve estimates significantly impact depreciation and depletion expense and the
calculation of potential impairments of oil and gas properties. Under the SEC rules, proved reserves
are those quantities of oil and gas, which, 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 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
75
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.
Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves but which, together with proved reserves, are as likely as not to be recovered. When
deterministic methods are used, it is as likely as not that actual remaining quantities recovered will
exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there
should be at least a 50% probability that the actual quantities recovered will equal or exceed the
proved plus probable reserves estimates.
Possible reserves are those additional reserves that are less certain to be recovered than probable
reserves. When deterministic methods are used, the total quantities ultimately recovered from a project
have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic
methods are used, there should be at least a 10% probability that the total quantities ultimately
recovered will equal or exceed the proved plus probable plus possible reserves estimates.
Reserves were calculated using an unweighted arithmetic average of commodity prices in effect on
the first day of each month within the twelve-month period ending on the date as of which the
applicable estimate is presented. These prices were adjusted for quality, transportation fees,
geographical differentials, marketing bonuses or deductions and other factors affecting the price
received at the wellhead.
Periodic revisions to the estimated reserves and related future cash flows may be necessary as a
result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices,
cost changes, technological advances, new geological or geophysical data or other economic factors.
Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are
ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such
revisions are significant, they could significantly affect future amortization of capitalized costs and result
in impairment of assets that may be material.
Property and Equipment. Oil and gas producing activities are accounted for using the successful
efforts method of accounting. Under the successful efforts method, lease acquisition costs and all
development costs, including unsuccessful development wells, are capitalized.
Unproved Properties—Acquisition costs associated with the acquisition of non-producing leaseholds
are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in
obtaining a mineral interest or right in a property, such as a lease in addition to options to lease,
broker fees, recording fees and other similar costs related to activities in acquiring properties.
Leasehold costs are classified as unproved until proved reserves are discovered, at which time related
costs are transferred to proved oil and gas properties.
Exploration Costs—Exploration costs, other than exploration drilling costs, are charged to expense
as incurred. These costs include seismic expenditures and other geological and geophysical costs,
amortization of unproved leasehold costs, and lease rentals. The costs of drilling exploratory wells and
exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well
has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful,
the cost of the well is transferred to expense.
Proved Oil and Gas Properties—Costs incurred to obtain access to proved reserves and to provide
facilities for extracting, treating, gathering, and storing oil, gas and NGLs are capitalized. All costs
incurred to drill and equip successful exploratory wells, development wells, development-type
stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
76
Impairment—The capitalized costs of proved oil and gas properties are reviewed at least annually
for impairment, whenever events or changes in circumstances indicate that the carrying amount of a
long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination
of recoverability is based on comparing the estimated undiscounted future net cash flows from a
producing field to the carrying value of the assets. If the future undiscounted cash flows, based on
estimates of anticipated production and future oil and natural gas prices and operating costs, are lower
than the carrying cost, the carrying cost of the field assets is reduced to fair value. For our proved oil
and gas properties, we estimate fair value by discounting the projected future cash flows at an
appropriate risk-adjusted discount rate.
Unproved leasehold costs are assessed at least annually to determine whether they have been
impaired. Individually significant properties are assessed for impairment on a property-by-property
basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If
unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is
recognized in the statement of operations.
Depreciation, Depletion and Amortization—Depreciation, depletion and amortization, or DD&A, of
capitalized costs of proved oil and gas properties is computed using the unit-of-production method
based upon estimated proved reserves. Assets are grouped for DD&A purposes on the basis of a
reasonable aggregation of properties producing from or expected to be developed in a basin or
formation. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to
acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.
The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which
include development costs and successful exploration drilling costs, includes only proved developed
reserves.
Sales—Sales of significant portions of a proved field are charged to income as incurred. Gain or
loss on the sale is recognized to the extent of the difference between the net proceeds received and the
remaining carrying value of the properties sold. Proceeds from the sale of insignificant portions of a
larger proved field are accounted for as a recovery of costs, thereby reducing the carrying value of the
field until such value reaches zero. For sales of entire working interests in unproved properties, gain or
loss is recognized to the extent of the difference between the proceeds received and the net carrying
value of the property. Proceeds from sales of partial interests in unproved properties are accounted for
as a recovery of costs unless the proceeds exceed the entire cost of the property.
Revenue Recognition. We recognize oil, gas and NGL revenues when products are delivered at a
fixed or determinable price, title has transferred and collectability is reasonably assured (sales method).
Oil and natural gas sold is not significantly different from our share of production.
Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in
the prices of oil, natural gas and NGLs. We record such derivative instruments as assets or liabilities in
the statements of financial position (see Note 4, ‘‘Fair Value Measurement,’’ in the Notes to
Consolidated Financial Statements for further information on fair value). Estimating the fair value of
derivative financial instruments requires management to make estimates and judgments regarding
volatility and counterparty credit risk. We use net presentation of derivative assets and liabilities when
such assets and liabilities are with the same counterparty and allowed under the ISDA trading
agreement with such counterparty.
We have not designated any of our derivative contracts as fair value or cash flow hedges. The
changes in fair value of the contracts are included in net income in the period of the change as ‘‘Net
gain (loss) on commodity derivatives.’’
Share-Based Compensation. We measure and record compensation expense for all share-based
payment awards to employees and directors based on estimated grant-date fair values. Compensation
77
costs for share-based awards are recognized over the requisite service period based on the grant-date
fair value. Prior to our IPO, we were not publicly traded, and did not have a listed price with which to
calculate fair value. We have historically and consistently calculated fair value using combined valuation
models including an enterprise valuation approach; an income approach, utilizing future discounted and
undiscounted cash flows; and a market approach, taking into consideration peer group analysis of
publicly traded companies, and when available, actual cash transactions in our common stock.
Acquisitions. Acquisitions are accounted for as purchases and, accordingly, the results of
operations are included in our statement of operations from the closing date of the acquisition.
Purchase prices are allocated to acquired assets and assumed liabilities, if any, based on their estimated
fair value at the time of the acquisition. We have historically and consistently calculated fair value using
combined valuation models including an enterprise valuation approach; an income approach, utilizing
future discounted and undiscounted cash flows; and a market approach, taking into consideration peer
group analysis of publicly traded companies.
Asset Retirement Obligations. We recognize as a liability an asset retirement obligation, or ARO,
associated with the retirement of a tangible long-lived asset in the period in which it is incurred or
becomes determinable (as defined by the standard), with an associated increase in the carrying amount
of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset
retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over
time as the discounted liability is accreted to its expected settlement value. We measure the fair value
of the ARO using expected future cash outflows for abandonment discounted generally at our cost of
capital at the time of recognition.
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. Inherent in the fair
value calculation are numerous 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.
Recent Accounting Pronouncements
In December 2011, the Financial Accounting Standards Board, or the FASB, issued an Accounting
Standards Update, or ASU, that requires an entity to disclose information about offsetting and related
arrangements to enable users of its financial statements to understand the effect of those arrangements
on its financial position. The ASU requires disclosure of both gross information and net information
about both instruments and transactions eligible for offset in the statement of financial position and
instruments and transactions subject to an agreement similar to a master netting arrangement. These
disclosure requirements are effective for interim and annual periods beginning after January 1, 2013.
We have provided all required disclosures for the periods presented as they pertain to its commodity
derivative instruments (see Note 4, ‘‘Fair Value Measurement’’ in Item 8. Financial Statements and
Supplementary Data). These disclosure requirements did not affect our operating results, financial
position, or cash flows.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to certain market risks that are inherent in our financial statements that arise in
the normal course of business. We may enter into derivative instruments to manage or reduce market
risk, but do not enter into derivative agreements for speculative purposes.
We do not designate these or future derivative instruments as hedges for accounting purposes.
Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.
78
Commodity price risk and hedges
Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently
volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized
prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and
NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to
reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we
engage in these activities as a hedging mechanism against price volatility associated with projected
production levels. The fair value of our oil, natural gas and NGL derivative contracts at December 31,
2013 was a net asset of $23.4 million.
As of December 31, 2013, we have hedged approximately 35% of our total forecasted production
from proved reserves through December 31, 2018. For information regarding the terms of these hedges,
please see ‘‘—Basis of presentation—Hedging’’ above. The production hedged thereby is consistent
with the anticipated monthly production levels in the December 31, 2013 reserve report prepared by
Cawley Gillespie, which is based on prices, costs and other assumptions required by SEC rules. Our
actual production will vary from the amounts estimated in this reserve report, perhaps materially.
Please read ‘‘Risk factors—Our estimated oil and natural gas reserve quantities and future production
rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in
these reserve estimates or the underlying assumptions will materially affect the quantities and present
value of our reserves.’’
Counterparty and customer credit risk
Joint interest receivables arise from billings to entities that own partial interests in the wells we
operate. These entities participate in our wells primarily based on their ownership in leases on which
we drill. We are also subject to credit risk due to concentration of our oil and natural gas receivables
with several significant customers. The inability or failure of these significant customers to meet their
obligations or their insolvency or liquidation may adversely affect our financial results. In addition, our
oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by
counterparties.
While we do not typically require our partners, customers and counterparties to post collateral and
we do not have a formal process in place to evaluate and assess the credit standing of our partners or
customers for oil and gas receivables and the counterparties on our derivative instruments, we do
evaluate the credit standing of such parties as we deem appropriate under the circumstances. This
evaluation may include reviewing a party’s credit rating, latest financial information and, in the case of
a customer with which we have receivables, their historical payment record, and undertaking the due
diligence necessary to determine creditworthiness. The counterparties on our derivative instruments
currently in place are lenders under the revolving credit facility with investment grade ratings. We are
not permitted under the terms of the revolving credit facility to enter into derivative instruments with
counterparties outside of the banks who are lenders under the revolving credit facility. As a result, any
future derivative instruments will be with these or other lenders under the revolving credit facility who
will also likely carry investment grade ratings.
Interest rate risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness.
The terms of the senior secured revolving credit facility and the second lien term loan provide for
interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins
ranging from 0.50% to 2.50% on the revolver and 6.0-7.0% on the term loan depending on the base
rate used and the amount of the loan outstanding in relation to the borrowing base. During the year
79
ended December 31, 2013, borrowings under the senior secured revolving credit facility and second lien
term loan bore interest at a weighted average rate of 3.01% and 9.19%, respectively.
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
None.
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 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. In light of the previously identified material weakness described below and
the insufficient time to test the operational effectiveness of our new processes and controls, our
principal executive officer and principal financial officer have concluded that our disclosure controls
and procedures were not effective at the reasonable assurance level as of December 31, 2013.
Changes in Internal Control over Financial Reporting
Prior to the completion of our initial public offering, we were a private company with limited
accounting personnel to adequately execute our accounting processes and limited other supervisory
resources with which to address our internal control over financial reporting. In previous years, we have
not maintained an effective control environment in that the design and execution of our controls has
not consistently resulted in effective review of our financial statements and supervision by appropriate
individuals. The lack of adequate staffing levels resulted in insufficient time spent on review and
approval of certain information used to prepare our financial statements. We concluded that these
control deficiencies, although varying in severity, constitute a material weakness in our control
environment.
Management has taken steps to address the causes of our audit adjustments and to improve our
internal control over financial reporting, including the implementation of new accounting processes and
control procedures and the identification of gaps in our skills base and expertise of the staff required to
meet the financial reporting requirements of a public company. Since July 2010, we have hired three
accounting managers along with a number of degreed staff accountants. This team has enabled us to
expedite our month-end close process, thereby facilitating the timely preparation of financial reports.
Likewise, we strengthened our internal control environment through the addition of skilled accounting
personnel. We continue to hire incremental qualified staff as needed in conjunction with a
comprehensive review of our internal controls and formalization of our review and approval processes.
We have designed but not fully implemented new processes and controls to remediate the material
weakness identified. There have been no changes in internal control over financial reporting during the
quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially
80
affect, our internal control over financial reporting. In the fourth quarter of 2013 we initiated our SOX
implementation process and hired a consulting firm to assist us in documenting our processes and
controls. Initial testing of our controls will commence in the first quarter of 2014. As of December 31,
2013, insufficient time has elapsed to test the operational effectiveness of these new controls, and as
such, we are unable to conclude the material weakness has been remediated.
Management’s Assessment of Internal Control over Financial Reporting
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every
public company that files reports with the SEC to include a management report on such company’s
internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business
Startups Act of 2012 (the ‘‘JOBS Act’’), our independent registered public accounting firm will not be
required to attest to the effectiveness of our internal control over financial reporting pursuant to
Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we
are no longer an ‘‘emerging growth company’’ as defined in the JOBS Act. This Annual Report on
Form 10-K does not include a report of management’s assessment regarding internal control over
financial reporting or an attestation report of our independent registered public accounting firm due to
a transition period established by SEC rules applicable to newly public companies. Our management
will be required to provide an assessment of the effectiveness of our internal control over financial
reporting as of December 31, 2014.
Item 9B. Other Information
None.
81
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information called for by this Item 10 is incorporated herein by reference to the definitive
Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and
Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by
this Annual Report on Form 10-K.
Item 11. Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the definitive
Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and
Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by
this Annual Report on Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The information called for by this Item 12 is incorporated herein by reference to the definitive
Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and
Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by
this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the definitive
Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and
Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by
this Annual Report on Form 10-K.
Item 14. Principal Accounting Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the definitive
Proxy Statement to be filed by the registrant pursuant to Regulation 14A of the General Rules and
Regulations under the Exchange Act not later than 120 days after the end of the fiscal year covered by
this Annual Report on Form 10-K.
82
Item 15. Exhibits, Financial Statement Schedules
PART IV
(a) The following documents are filed as part of this report or incorporated by reference:
(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.
(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.
(3) Exhibits. The exhibits required to be filed by this Item 15 are set forth in the Exhibit
Index accompanying this Annual Report on Form 10-K.
83
Exhibit No.
2.1
2.2*
3.1
3.2
4.1
4.2
10.1
10.2
10.3
10.4†
10.5†
10.6†
10.7†
10.8†
EXHIBIT INDEX
Description
Purchase and Sale Agreement by and between Chalker Energy Partners II, LLC, the
listed participating owners and Jones Energy Holdings, LLC, dated November 28, 2012
(incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on
Form S-1, File No. 333-188896, filed on June 7, 2013).
Purchase and Sale Agreement by and between Sabine Mid-Continent LLC, as seller, and
Jones Energy Holdings, LLC, as purchaser, dated as of November 22, 2013.
Amended and Restated Certificate of Incorporation of Jones Energy, Inc. (incorporated
by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on
July 30, 2013).
Amended and Restated Bylaws of Jones Energy, Inc. (incorporated by reference to
Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on July 30, 2013).
Form of Class A common stock Certificate (incorporated by reference to Exhibit 4.2 to
the Company’s Registration Statement on Form S-1, File No. 333-188896, filed on
June 7, 2013).
Registration Rights and Stockholders Agreement, dated as of July 29, 2013 (incorporated
by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on
July 30, 2013).
Third Amended and Restated Limited Liability Company Agreement of Jones Energy
Holdings, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current
Report on Form 8-K filed on July 30, 2013).
Exchange Agreement, dated as of July 29, 2013, by and among Jones Energy, Inc., Jones
Energy Holdings, LLC and the members of Jones Energy Holdings, LLC party thereto
(incorporated by reference to Exhibit 10.3 to the Company’s Current Report on
Form 8-K filed on July 30, 2013).
Tax Receivable Agreement, dated as of July 29, 2013, by and among Jones Energy, Inc.,
Jones Energy Holdings, LLC and the members of Jones Energy Holdings, LLC party
thereto (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on
Form 8-K filed on July 30, 2013).
Jones Energy, Inc. 2013 Omnibus Incentive Plan, effective as of July 29, 2013
(incorporated by reference to Exhibit 10.6 to the Company’s Current Report on
Form 8-K filed on July 30, 2013).
Jones Energy, Inc. Short Term Incentive Plan, effective as of July 29, 2013 (incorporated
by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed on
July 30, 2013).
Form of Director Restricted Stock Award Agreement (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 4, 2013).
Form of Employee Restricted Stock Award Agreement (incorporated by reference to
Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on September 4, 2013).
Jones Energy, LLC Executive Deferral Plan (incorporated by reference to Exhibit 10.1 to
the Company’s Current Report on Form 8-K filed on October 23, 2013).
84
Exhibit No.
10.9†
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19*
10.20*
Description
Jones Energy Holdings, LLC Monarch Equity Plan (incorporated by reference to
Exhibit 10.8 to the Company’s Registration Statement on Form S-1, File No. 333-188896,
filed on May 28, 2013).
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 to the
Company’s Registration Statement on Form S-1, File No. 333-188896, filed on June 7,
2013).
Credit Agreement, dated as of December 31, 2009, among Jones Energy Holdings, LLC,
as borrower, Wells Fargo Bank N.A., as administrative agent, and the lenders party
thereto (incorporated by reference to Exhibit 10.9 to the Company’s Registration
Statement on Form S-1, File No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 1 to Credit Agreement (First Lien) (incorporated by
reference to Exhibit 10.10 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Master Assignment, Agreement and Amendment No. 2 to Credit Agreement
(incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on
Form S-1, File No. 333-188896, filed on May 28, 2013).
Master Assignment, Agreement and Amendment No. 3 to Credit Agreement
(incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on
Form S-1, File No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 4 to Credit Agreement (First Lien) (incorporated by
reference to Exhibit 10.13 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Master Assignment, Agreement and Amendment No. 5 to Credit Agreement
(incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on
Form S-1, File No. 333-188896, filed on May 28, 2013).
Waiver and Amendment No. 6 to Credit Agreement (incorporated by reference to
Exhibit 10.15 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Waiver, Agreement and Amendment No. 7 to Credit Agreement and Amendment to
Guarantee and Collateral Agreement (incorporated by reference to Exhibit 10.24 to the
Company’s Registration Statement on Form S-1, File No. 333-188896, filed on June 17,
2013).
Borrowing Base Increase Agreement, dated as of December 18, 2013, among Jones
Energy Holdings, LLC, as borrower, certain subsidiaries of Jones Energy Holdings, LLC,
as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party
thereto.
Agreement and Amendment No. 8 to Credit Agreement dated as of January 29, 2014,
among Jones Energy Holdings, LLC, as borrower, Jones Energy, Inc., Jones
Energy, LLC and Nosley Assets, LLC, as guarantors, Wells Fargo Bank, N.A., as
administrative agent, and the lenders party thereto.
10.21*
Guarantee and Collateral Agreement, dated as of January 29, 2014, between Jones
Energy, Inc., as guarantor, and Wells Fargo Bank, N.A., as administrative agent.
85
Exhibit No.
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
99.1*
Description
Second Lien Credit Agreement, dated as of December 31, 2009, among Jones Energy
Holdings, LLC, as borrower, Wells Fargo Energy Capital, Inc., as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.16 to the
Company’s Registration Statement on Form S-1, File No. 333-188896, filed on May 28,
2013).
Agreement and Amendment No. 1 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 2 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 3 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 4 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Agreement and Amendment No. 5 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Waiver and Amendment No. 6 to Second Lien Credit Agreement (incorporated by
reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-1, File
No. 333-188896, filed on May 28, 2013).
Waiver, Agreement and Amendment No. 7 to Second Lien Credit Agreement
(incorporated by reference to Exhibit 10.25 to the Company’s Registration Statement on
Form S-1, File No. 333-188896, filed on June 17, 2013).
List of Subsidiaries of Jones Energy, Inc.
Consent of PricewaterhouseCoopers LLP.
Consent of Cawley Gillespie & Associates, Inc.
Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).
Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).
Section 1350 Certification of Jonny Jones (Principal Executive Officer).
Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
Summary Report of Cawley, Gillespie & Associates, Inc. for reserves as of December 31,
2013
101.INS** XBRL Instance Document.
101.SCH** XBRL Taxonomy Extension Schema Document.
101.CAL** XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF** XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB** XBRL Taxonomy Extension Label Linkbase Document.
86
Exhibit No.
Description
101.PRE** XBRL Taxonomy Extension Presentation Linkbase Document.
*—filed herewith
**—furnished herewith
†—Management contract or compensatory plan or arrangement required to be filed as an exhibit to
this 10-K pursuant to Item 15(b).
87
Pursuant to the requirements 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
JONES ENERGY, INC.
(registrant)
Date: March 14, 2014
By:
/s/ JONNY JONES
Name: Jonny Jones
Title: Chief Executive Officer
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 indicated.
Name
Title
Date
/s/ JONNY JONES
Jonny Jones
Chairman of the Board of Directors
and Chief Executive Officer (Principal
Executive Officer)
March 14, 2014
/s/ MIKE S. MCCONNELL
Mike S. McConnell
Director and President
March 14, 2014
/s/ ROBERT J. BROOKS
Robert J. Brooks
Executive Vice President and Chief
Financial Officer (Principal Accounting
and Financial Officer)
March 14, 2014
/s/ HOWARD I. HOFFEN
Howard I. Hoffen
/s/ GREGORY D. MYERS
Gregory D. Myers
/s/ HALBERT S. WASHBURN
Halbert S. Washburn
/s/ ALAN D. BELL
Alan D. Bell
Director
Director
Director
Director
88
March 14, 2014
March 14, 2014
March 14, 2014
March 14, 2014
GLOSSARY OF OIL AND NATURAL GAS TERMS
The terms and abbreviations defined in this section are used throughout this Annual Report on
Form 10K:
‘‘AMI’’—Area of mutual interest, typically referring to a contractually defined area under a joint
development agreement whereby parties are subject to mutual participatory rights and restrictions.
‘‘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 NGLs.
‘‘Boe’’—Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel
of oil.
‘‘Boe/d’’—Barrels of oil equivalent per day.
‘‘British thermal unit (BTU)’’—The heat required to raise the temperature of one pound 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.
‘‘Condensate’’—Liquid hydrocarbons associated with the production of a primarily natural gas
reserve.
‘‘Developed acreage’’—The number of acres that are allocated or assignable to productive wells or
wells capable of production.
‘‘Developed reserves’’—Reserves of any category that can be expected to be recovered (i) through
existing wells with existing equipment and operating methods or in which the cost of the required
equipment is relatively minor when compared to the cost of a new well; and (ii) through installed
extraction equipment and infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
‘‘Development well’’—A well drilled within the proved area of a natural gas or oil 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 do not exceed production expenses and taxes.
‘‘Economically producible’’—A resource which generates revenue that exceeds, or is reasonably
expected to exceed, the costs of the operation.
‘‘Exploratory well’’—A well drilled to find and produce oil or natural gas reserves not classified as
proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in
another reservoir or to extend a known reservoir.
‘‘Farm-in or farm-out’’—An agreement under which the owner of a working interest in an oil or
natural gas lease assigns the working interest or a portion of the working interest to another party who
desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in
order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest
in the lease. The interests received by an assignee is a ‘‘farm-in’’ while the interest transferred by the
assignor is a ‘‘farm-out.’’
89
‘‘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.
‘‘Formation’’—A layer of rock which has distinct characteristics that differ from nearby rock.
‘‘Fracture stimulation’’—A process whereby fluids mixed with proppants are injected into a wellbore
under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural
gas trapped in the reservoir rock to travel through the fractures and into the well for production.
‘‘Gross acres or gross wells’’—The total acres or well, as the case may be, in which a working
interest is owned.
‘‘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.
‘‘Joint development agreement’’—Includes joint venture agreements, farm-in and farm-out
agreements, joint operating agreements and similar partnering arrangements.
‘‘MBbl’’—One thousand barrels of oil, condensate or NGLs.
‘‘MBoe’’—One thousand barrels of oil equivalent, determined using the equivalent of six Mcf of
natural gas to one Bbl of crude oil.
‘‘Mcf’’—One thousand cubic feet of natural gas.
‘‘MMBoe’’—One million barrels of oil equivalent.
‘‘MMBtu’’—One million British thermal units.
‘‘MMcf’’—One million cubic feet of natural gas.
‘‘Net acres or net wells’’—The sum of the fractional working interest owned in gross acres or gross
wells. An owner who has 50% interest in 100 acres owns 50 net acres.
‘‘Net revenue interest’’—An owner’s interest in the revenues of a well after deducting proceeds
allocated to royalty and overriding interests.
‘‘Possible reserves’’—Additional reserves that are less certain to be recognized than probable
reserves.
‘‘Probable reserves’’—Additional reserves that are less certain to be recognized than proved reserves
but which, in sum with proved reserves, are as likely as not to be recovered.
‘‘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.
‘‘Prospect’’—A specific geographic area which, based on supporting geological, geophysical or other
data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered
to have potential for the discovery of commercial hydrocarbons.
‘‘Proved developed non-producing’’—Hydrocarbons in a potentially producing horizon penetrated by
a wellbore, the production of which has been postponed pending installation of surface equipment or
gathering facilities, or pending the production of hydrocarbons from another formation penetrated by
the wellbore. The hydrocarbons are classified as proved but non-producing reserves.
‘‘Proved developed reserves’’—Proved reserves that can be expected to be recovered through existing
wells and facilities and by existing operating methods.
‘‘Proved reserves’’—Reserves of oil and natural gas that have been proved to a high degree of
certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate
geological and engineering data.
90
‘‘Proved undeveloped reserves (PUD)’’—Proved reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major expenditure is required for
recompletion.
‘‘Recompletion’’—The process of re-entering an existing wellbore that is either producing or not
producing and completing new reservoirs in an attempt to establish or increase existing production.
‘‘Reserves’’—Estimated remaining quantities of oil and natural gas and related substances
anticipated to be economically producible as of a given date by application of development projects to
known accumulations.
‘‘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
individual and separate from other reservoirs.
‘‘Royalty interest’’—An interest in an oil and natural gas property entitling the owner to a share of
oil or gas production free of production costs.
‘‘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.
‘‘Spud’’—The commencement of drilling operations of a new well.
‘‘Standardized measure of discounted future net cash flows’’—The present value of estimated future
net revenues to be generated from the production of proved reserves, determined in accordance with
the regulations of the Securities and Exchange Commission, without giving effect to non-property
related expenses such as general and administrative expenses, debt service, future income tax expenses
or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.
‘‘Trend’’—A region of oil and/or natural gas production, the geographic limits of which have not
been fully defined, having geological characteristics that have been ascertained through supporting
geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a
particular formation or series of formations.
‘‘Unconventional formation’’—A term used in the oil and natural gas industry to refer to a
formation in which the targeted reservoirs generally fall into one of three categories: (1) tight sands,
(2) coal beds, or (3) oil and gas shales. The reservoirs tend to cover large areas and lack the readily
apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional
reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery
processes in order to produce economic flow rates
‘‘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.
‘‘Wellbore’’—The hole drilled by the bit that is equipped for oil or gas production on a completed
well. Also called well or borehole.
‘‘Working interest’’—The right granted to the lessee of a property to explore for and to produce and
own oil, gas, or other minerals and receive a share of the production. The working interest owners bear
the exploration, development, and operating costs of the property.
91
Index to Financial Statements
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-2
Consolidated Financial Statements
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Changes in Stockholders’ / Members’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-3
F-4
F-5
F-6
F-7
Supplemental Information on Oil and Gas Producing Activities . . . . . . . . . . . . . . . . . . . . . . . . . F-31
Supplemental Quarterly Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-35
F-1
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Jones Energy, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated
statements of operations, changes in stockholders’ / members’ equity, and cash flows present fairly, in
all material respects, the financial position of Jones Energy, Inc. and its subsidiaries at December 31,
2013 and 2012 and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2013 in conformity with accounting principles generally accepted in the
United States of America. 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 of these statements 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, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 14, 2014
F-2
Jones Energy, Inc
Consolidated Balance Sheets
December 31, 2013 and 2012
(in thousands of dollars)
Assets
Current assets
December 31,
2013
December 31,
2012
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Joint interest owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas properties, net, at cost under the successful efforts method . . . . . . . . . .
Other property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets
$
23,820
45
$
23,726
—
51,233
42,481
1,459
8,837
2,392
12
130,279
1,312,551
3,444
25,398
15,006
1,301
29,684
21,876
4,590
17,648
1,088
—
98,612
1,007,344
3,398
25,199
16,133
—
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,487,979
$1,150,686
Liabilities and Stockholders’ / Members’ Equity
Current liabilities
Trade accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas sales payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies (Note 10)
Stockholders’ / members’ equity
Members’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Class A common stock, $0.001 par value; 12,526,580 shares issued and outstanding
Class B common stock, $0.001 par value; 36,836,333 shares issued and outstanding
Additional paid-in-capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stockholders’ / members’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ / members’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
89,430
66,179
10,805
10,664
—
2,590
179,668
658,000
14,531
190
8,373
3,093
863,855
—
13
37
173,169
(2,186)
171,033
453,091
624,124
$
38,036
45,860
5,255
4,035
61
174
93,421
610,000
—
7,657
9,332
1,876
722,286
428,400
—
—
—
—
428,400
—
428,400
Total liabilities and stockholders’ / members’ equity . . . . . . . . . . . . . . . . . . .
$1,487,979
$1,150,686
The accompanying notes are an integral part of these consolidated financial statements.
F-3
Jones Energy, Inc.
Consolidated Statements of Operations
Years Ended December 31, 2013, 2012 and 2011
(in thousands except per share data)
Operating revenues
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2013
2012
2011
$258,063
1,106
$148,967
847
$167,261
1,022
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
259,169
149,814
168,283
Operating costs and expenses
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative (including non-cash compensation
27,781
12,865
1,710
114,136
14,415
608
23,097
5,583
356
80,709
18,821
533
21,548
5,333
780
68,906
31,970
413
expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31,902
15,875
16,679
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
203,417
144,974
145,629
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55,752
4,840
22,654
Other income (expense)
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain (loss) on commodity derivatives . . . . . . . . . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain (loss) on sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(30,774)
(2,566)
—
(78)
Other income (expense), net . . . . . . . . . . . . . . . . . . . . . . . . . . .
(33,418)
Income (loss) before income tax . . . . . . . . . . . . . . . . . . . . . . . .
22,334
(25,292)
16,684
—
1,162
(7,446)
(2,606)
(21,994)
34,490
26,208
(859)
37,845
60,499
Income tax provision
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85
(156)
(71)
—
473
473
—
173
173
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to non-controlling interests . . . . . . . . . . . . .
22,405
24,591
(3,079)
—
60,326
—
Net income (loss) attributable to controlling interests . . . . . . . . . . . .
$ (2,186) $ (3,079) $ 60,326
Earnings per share:
Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(0.17)
Weighted average shares outstanding:
Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,500
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Jones Energy, Inc.
Statement of Changes in Stockholders’ / Members’ Equity
Years Ended December 31, 2013, 2012 and 2011
(amounts in thousands)
Balance at December 31, 2010 .
.
Stock-compensation expense .
.
.
.
Net income .
. .
.
.
.
.
.
.
.
.
.
Balance at December 31, 2011 .
.
Issuance of Class C preferred units
.
Stock-compensation expense .
.
.
Net income (loss) .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Balance at December 31, 2012 .
Issuance of common stock .
.
.
Proceeds from the sale of common stock .
Reclassification of members’ contributions
.
Stock-compensation expense .
.
.
Distribution to members .
.
.
.
Net income .
. .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Balance at December 31, 2013 .
.
.
.
.
.
.
Common Stock
Class A
Class B
Shares Value Shares Value
Members’
Equity
Additional
Paid-in- Retained Non-controlling
Capital
Interest
Deficit
.
.
.
.
.
.
.
— $—
— —
— —
— —
— —
— —
— —
.
. 12,500
.
.
.
.
.
— —
13
— —
— —
— —
— —
— —
— $— $ 284,449
1,134
— —
60,326
— —
$
— $ —
—
—
—
—
$
— —
— —
— —
— —
345,909
85,000
570
(3,079)
—
—
—
—
—
—
—
—
—
—
—
—
36,836
— —
37
— —
— — (464,037)
10,100
— —
(10,000)
— —
35,537
— —
—
428,400
—
—
—
—
— 172,431
—
—
—
738
—
—
—
— (2,186)
—
—
—
464,037
—
—
(10,946)
Total
Stockholders’ /
Members’ Equity
$284,449
1,134
60,326
345,909
85,000
570
(3,079)
428,400
50
172,431
—
10,838
(10,000)
22,405
. 12,500
$13
36,836
$37
$
— $173,169
$(2,186)
$453,091
$624,124
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Jones Energy, Inc.
Consolidated Statements of Cash Flows
Years Ended December 31, 2013, 2012 and 2011
(in thousands of dollars)
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
activities
Exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation, and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-cash compensation expense (Note 9) . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on commodity derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on bargain purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Gain) loss on sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other—net
Changes in assets and liabilities
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2013
2012
2011
$ 22,405
$
(3,079) $ 60,326
—
114,136
14,415
608
2,677
10,838
2,719
(469)
2,566
—
78
(156)
79
(41,481)
163
35,318
—
80,709
18,821
533
3,544
570
—
—
(16,684)
—
(1,162)
473
129
11,568
1,873
(12,745)
478
68,906
31,970
413
2,940
1,134
—
—
(34,490)
(26,208)
859
173
(59)
(32,593)
(3,360)
49,728
Net cash provided by operations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
163,896
84,550
120,217
Cash flows from investing activities
Additions to oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of other property, plant and equipment . . . . . . . . . . . . . . . . . . . .
Current period settlements of matured derivative contracts . . . . . . . . . . . . . . .
Change in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(197,618)
(193,496)
1,607
(1,634)
7,586
(45)
(125,493)
(249,007)
9,158
(969)
28,675
—
(157,046)
(168,480)
6,747
(1,735)
1,551
—
Net cash used in investing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(383,600)
(337,636)
(318,963)
Cash flows from financing activities
Proceeds from issuance of long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment under long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of preferred units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of common stock, net of expenses of $15.1 million . . . . . . .
220,000
(172,000)
(683)
—
172,481
233,243
(38,243)
(9,324)
85,000
—
316,500
(126,500)
(3,678)
—
—
Net cash provided by financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
219,798
270,676
186,322
Net increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
94
17,590
(12,424)
Cash
Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23,726
6,136
18,560
End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 23,820
$ 23,726
$
6,136
Supplemental disclosure of cash flow information
Cash paid for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in accrued additions to oil and gas properties . . . . . . . . . . . . . . . . . .
Noncash acquisition of oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . .
Current additions to ARO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncash distributions to members (Note 9) . . . . . . . . . . . . . . . . . . . . . . . . .
$ 25,414
41,945
—
1,516
10,000
$ 20,759
3,355
2,918
662
—
$ 18,151
26,774
—
4,077
—
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Jones Energy, Inc.
Notes to Consolidated Financial Statements
1. Organization and Description of Business
Organization
Jones Energy, Inc. (the ‘‘Company’’) was formed in March 2013 as a Delaware corporation to
become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC (‘‘JEH’’). As
the sole managing member of JEH, Jones Energy, Inc. is responsible for all operational, management
and administrative decisions relating to JEH’s business and consolidates the financial results of JEH
and its subsidiaries.
JEH was formed as a Delaware limited liability company on December 16, 2009 through
investments made by the Jones family and through private equity funds managed by Metalmark Capital
and Wells Fargo Energy Capital. JEH acts as a holding company of operating subsidiaries that own and
operate assets that are used in the exploration, development, production and acquisition of oil and
natural gas properties.
Pursuant to the terms of a corporate reorganization that was completed in connection with the
closing of Jones Energy, Inc.’s initial public offering (‘‘IPO’’) on July 29, 2013, the pre-IPO owners of
JEH converted their existing membership interests in JEH into JEH Units and amended the
existing LLC agreement to, among other things, modify its equity capital to consist solely of JEH Units
and to admit Jones Energy, Inc. as the sole managing member of JEH. Jones Energy, Inc.’s certificate
of incorporation authorizes two classes of common stock, Class A common stock and Class B common
stock. Only Class A common stock was offered to investors pursuant to the IPO. The Class B common
stock is held by the pre-IPO owners of JEH and can be exchanged (together with a corresponding
number of JEH Units) for shares of Class A common stock on a one-for-one basis, subject to
customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other
similar transactions. The Class B common stock has no economic rights but entitles its holder to one
vote on all matters to be voted on by the Company’s stockholders generally. As a result of the IPO, the
pre-IPO owners retained 74.7% of the total economic interest in JEH, but with no voting rights or
management power over JEH, resulting in the Company reporting this ownership interest as a
non-controlling interest. Prior to the IPO, JEH owned the controlling interest in the Company; hence
all of the net income (loss) earned prior to the IPO date is reflected in the net income (loss)
attributable to non-controlling interests on the Consolidated Statement of Operations for the year
ended December 31, 2013.
Description of Business
The Company is engaged in the acquisition, exploration, and production of oil and natural gas
properties in the mid-continent United States. The Company’s assets are located within two distinct
basins in the Texas Panhandle and Oklahoma, the Anadarko Basin and the Arkoma Basin, and are
owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.
Revision of Previously Issued Financial Statements
We identified an error in our previously issued financial statements which would have been
material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period.
Therefore we have revised our Consolidated Statement of Operations for the years ended
December 31, 2012 and 2011 to record $0.6 million and $0.8 million, respectively of additional interest
expense on obligations that are unrelated to our credit agreements discussed in Note 6. As a result, net
income decreased for the years ended December 31, 2012 and 2011 by $0.6 million and $0.8 million,
F-7
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
1. Organization and Description of Business (Continued)
respectively. The balance sheet impacts of the revision are increases in accrued liabilities and decreases
in members’ equity of $0.6 million and $1.4 million at December 31, 2011 and 2012, respectively. These
revisions had no impact on our net cash provided by operations in our Consolidated Statement of Cash
Flows. We have determined that these errors are not material to our consolidated financial statements
for the years ended December 31, 2012 and 2011.
2. Significant Accounting Policies
Basis of Presentation
The accompanying financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America (‘‘GAAP’’). All significant intercompany
transactions and balances have been eliminated in consolidation. The financial statements reported for
December 31, 2013, 2012 and 2011, and the years then ended include the Company and all of its
subsidiaries.
Segment Information
The Company operates in one industry segment, which is the exploration, development and
production of oil and natural gas, and all of its operations are conducted in one geographic area of the
United States.
Use of Estimates
In preparing the accompanying financial statements, management has made certain estimates and
assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities,
and the reported amounts of revenue and expenses during the reporting period. Actual results could
differ from these estimates. Changes in estimates are recorded prospectively.
Significant assumptions are required in the valuation of proved oil and natural gas reserves, which
affect the Company’s estimates of depletion expense, impairment, and the allocation of value in our
business combinations. Significant assumptions are also required in the Company’s estimates of the net
gain or loss on commodity derivative assets and liabilities, fair value associated with business
combinations, and asset retirement obligations (‘‘ARO’’).
Financial Instruments
Cash, accounts receivable and accounts payable are recorded at cost. The fair value of accounts
receivable and accounts payable are not materially different from their carrying amounts because of the
short-term nature of these instruments. The carrying values of outstanding balances under the
Company’s credit agreements represent fair value because the agreements have variable interest rates,
which are reflective of the Company’s credit risk. Derivative instruments are recorded at fair value, as
discussed below.
Cash
Cash and cash equivalents include highly liquid investments with a maturity of three months or
less. At times, the amount of cash on deposit in financial institutions exceeds federally insured limits.
F-8
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Management monitors the soundness of the financial institutions and believes the Company’s risk is
negligible.
Accounts Receivable
Accounts receivable—Oil and gas sales consist of uncollateralized accrued revenues due under
normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts
receivable—Joint interest owners consist of uncollateralized joint interest owner obligations due within
30 days of the invoice date. Accounts receivable—Other consist primarily of severance tax refunds due
from state agencies. No interest is charged on past-due balances. The Company routinely assesses the
recoverability of all material trade, joint interest and other receivables to determine their collectability,
and reduces the carrying amounts by a valuation allowance that reflects management’s best estimate of
the amounts that may not be collected. As of December 31, 2013 and 2012, the Company did not have
significant allowances for doubtful accounts.
Concentration of Risk
Substantially all of the Company’s accounts receivable are related to the oil and gas industry. This
concentration of entities may affect the Company’s overall credit risk in that these entities may be
affected similarly by changes in economic and other conditions. As of December 31, 2013, 79% of
Accounts receivable—Oil and gas sales are due from 8 purchasers and 77% of Accounts receivable—
Joint interest owners are due from 5 working interest owners. As of December 31, 2012, 92% of
Accounts receivable—Oil and gas sales were due from 8 purchasers, and 72% of 2012 Accounts
receivable—Joint interest owners were due from 5 working interest owners. If any or all of these
significant counterparties were to fail to pay amounts due to the Company, the Company’s financial
position and results of operations could be materially and adversely affected.
Dependence on Major Customers
The Company maintains a portfolio of crude oil and natural gas marketing contracts with large,
established refiners and oil and gas purchasers. During the year ended December 31, 2013, the largest
purchasers were PVR Midstream, Unimark LLC, Mercuria, Valero, and Plains Marketing, which
accounted for approximately 15%, 13%, 13%, 13% and 6% of consolidated oil and gas sales,
respectively. During the year ended December 31, 2012, the largest purchasers were Unimark LLC,
Mercuria, PVR Midstream, and Plains Marketing, which accounted for approximately 24%, 18%, 18%
and 15% of consolidated oil and gas sales, respectively. During the year ended December 31, 2011, the
largest purchasers were Plains Marketing, PVR Midstream, Unimark LLC, and Valero Marketing,
which accounted for approximately 27%, 22%, 13% and 9% of consolidated oil and gas sales,
respectively.
Management believes that there are alternative purchasers and that it may be necessary to
establish relationships with such new purchasers. However, there can be no assurance that the
Company can establish such relationships and that those relationships will result in an increased
number of purchasers. Although the Company is exposed to a concentration of credit risk, management
believes that all of the Company’s purchasers are credit worthy.
F-9
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Dependence on Suppliers
The Company’s industry is cyclical, and from time to time, there is a shortage of drilling rigs,
equipment, services, supplies and qualified personnel. During these periods, the costs and delivery
times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high
cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in its
areas of operation, the Company could be materially and adversely affected. Management believes that
there are potential alternative providers of drilling and completion services and that it may become
necessary to establish relationships with new contractors. However, there can be no assurance that the
Company can establish such relationships and that those relationships will result in increased
availability of drilling rigs or other services, or that they could be obtained on the same terms.
Oil and Gas Properties
The Company accounts for its oil and natural gas exploration and production activities under the
successful efforts method of accounting. Oil and gas properties consisted of the following at
December 31, 2013 and 2012:
(in thousands of dollars)
Mineral interests in properties
2013
2012
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wells and equipment and related facilities . . . . . . . . . . . . .
$ 114,457
958,816
609,748
$ 137,254
737,558
389,727
Less: Accumulated depletion and impairment
. . . . . . . . . .
1,683,021
(370,470)
1,264,539
(257,195)
Net oil and gas properties . . . . . . . . . . . . . . . . . . . . .
$1,312,551
$1,007,344
Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill
and equip development wells and the related asset retirement costs are capitalized. The costs to drill
and equip exploratory wells are capitalized pending determination of whether the Company has
discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling
costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial
reserves have been found when drilling has been completed. Such exploratory well drilling costs may
continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a
producing well and sufficient progress in assessing the reserves and the economic and operating
viability of the project is being made. In 2013, we had no material capitalized costs associated with
exploratory wells. As of December 31, 2012, there were no costs capitalized in connection with
exploratory wells in progress.
The Company capitalizes interest on expenditures for significant exploration and development
projects that last more than six months while activities are in progress to bring the assets to their
intended use. The Company did not capitalize any interest in 2013 as no projects lasted more than six
months. During the year ended December 31, 2012, the Company capitalized $0.1 million in interest.
Costs incurred to maintain wells and related equipment are charged to expense as incurred.
F-10
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
On the sale or retirement of a proved field, the cost and related accumulated depletion,
depreciation and amortization are eliminated from the field accounts, and the resultant gain or loss is
recognized.
Capitalized amounts attributable to proved oil and gas properties are depleted by the
unit-of-production method over proved reserves, using the unit conversion ratio of six thousand cubic
feet of gas to one barrel of oil equivalent. Depletion of the costs of wells and related equipment and
facilities, including capitalized asset retirement costs, net of salvage values, is computed using proved
developed reserves. The reserve base used to calculate depreciation, depletion, and amortization for
leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed
reserves and proved undeveloped reserves. Depletion of oil and gas properties amounted to
$113.3 million, $79.9 million and $68.2 million for the years ended December 31, 2013, 2012 and 2011,
respectively.
The Company reviews its proved oil and natural gas properties, including related wells and
equipment, for impairment by comparing expected undiscounted future cash flows at a producing field
level to the net capitalized cost of the asset. If the future undiscounted cash flows, based on the
Company’s estimate of future commodity prices, operating costs, and production, are lower than the
net capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting
the future cash flows at an appropriate risk-adjusted discount rate. Due to the significant assumptions
associated with the inputs and calculations described, the fair value of oil and gas properties used in
estimating impairment represents a nonrecurring Level 3 measurement. The Company incurred
impairment charges of $18.8 million and $19.8 million related to its proved oil and natural gas
properties and equipment in 2012 and 2011, respectively. No impairments of proved properties were
recorded in 2013.
The Company evaluates its unproved properties for impairment on a property-by-property basis.
The Company’s unproved property consists of acquisition costs related to its undeveloped acreage. The
Company reviews the unproved property for indicators of impairment based on the Company’s current
exploration plans with consideration given to results of any drilling and seismic activity during the
period and known information regarding exploration activity by other companies on adjacent blocks. In
the fourth quarter of 2013, the Company recorded an impairment charge of $14.4 million related to its
unproved Southridge properties. As the Company did not drill the required number of wells by
October 31, 2013 necessary to keep its joint development agreement with Southridge in effect, the
Company lost its right to the undeveloped acreage. The Company incurred no impairment charges
related to its unproved properties in 2012. In 2011, the Company incurred a $12.2 million impairment
charge related to its unproven properties in fields which were not expected to produce natural gas with
a sufficiently high liquid content reducing the economic return of those fields. These charges represent
nonrecurring Level 3 measurements. Impairment of oil and gas properties charges are recorded on the
Consolidated Statement of Operations.
On the sale of an entire interest in an unproved property, gain or loss on the sale is recognized,
taking into consideration the amount of any recorded impairment if the property had been assessed
individually. If a partial interest in an unproved property is sold, the amount received is treated as a
reduction of the cost of the interest retained.
F-11
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Other Property, Plant and Equipment
Other property, plant and equipment consisted of the following at December 31, 2013 and 2012:
(in thousands of dollars)
Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Furniture, fixtures, computers and software . . . . . . . . . . . . . . . . .
Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aircraft
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Accumulated depreciation and amortization . . . . . . . . . . . .
2013
2012
$ 1,060
2,491
835
910
134
$
983
2,204
719
1,295
134
5,430
(1,986)
5,335
(1,937)
Net other property, plant and equipment
. . . . . . . . . . . . . . . .
$ 3,444
$ 3,398
Other property, plant and equipment is depreciated on a straight-line basis over the estimated
useful lives of the property, plant and equipment, which range from three years to ten years.
Depreciation and amortization of other property, plant and equipment amounted to $0.8 million,
$0.8 million and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.
Oil and Gas Sales Payable
Oil and gas sales payable represents amounts collected from purchasers for oil and gas sales, which
are due to other revenue interest owners. Generally, the Company is required to remit amounts due
under these liabilities within 60 days of receipt.
Commodity Derivatives
The Company records its commodity derivative instruments on the Consolidated Balance Sheet as
either an asset or liability measured at its fair value. Changes in the derivative’s fair value are
recognized currently in earnings, unless specific hedge accounting criteria are met. During the years
ended December 31, 2013, 2012 and 2011, the Company elected not to designate any of its commodity
price risk management activities as cash flow or fair value hedges. The changes in the fair values of
outstanding financial instruments are recognized as gains or losses in the period of change.
Although Jones does not designate its commodity derivative instruments as cash-flow hedges,
management uses those instruments to reduce the Company’s exposure to fluctuations in commodity
prices related to its natural gas and oil production. Net gains and losses, at fair value, are included on
the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated
timing of cash settlements under the related contracts. Changes in the fair value of commodity
derivative contracts are recorded in earnings as they occur and are included in other income (expense)
on the Consolidated Statement of Operations. See Note 4, ‘‘Fair Value Measurement,’’ for disclosure
about the fair values of commodity derivative instruments.
Asset Retirement Obligations
The Company’s asset retirement obligations consist of future plugging and abandonment expenses
on oil and natural gas properties. The Company estimates an ARO for each well in the period in which
F-12
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
it is incurred based on estimated present value of plugging and abandonment costs, increased by an
inflation factor to the estimated date that the well would be plugged. The resulting liability is recorded
by increasing the carrying amount of the related long-lived asset. The liability is then accreted to its
then-present value each period and the capitalized cost is depleted over the useful life of the related
asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is
recognized. The ARO is classified as current or noncurrent based on the expect timing of payments. A
summary of the Company’s ARO for the years ended December 31, 2013 and 2012 is as follows:
(in thousands of dollars)
ARO liability at beginning of year . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities incurred(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled due to sale of related properties . . . . . . . . . . . .
Liabilities settled due to plugging and abandonment . . . . . . . . . . .
Change in estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013
2012
$ 9,506
1,515
608
(271)
(702)
307
$9,563
662
596
(927)
(388)
—
ARO liability at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Current portion of ARO at end of year . . . . . . . . . . . . . . .
10,963
(2,590)
9,506
(174)
Total long-term ARO at end of year . . . . . . . . . . . . . . . . . . . . . .
$ 8,373
$9,332
(1) Includes $824 related to wells acquired (see Note 3, ‘‘Acquisition of Properties’’).
Revenue Recognition
Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the
product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably
assured and evidenced by a contract. The Company follows the ‘‘sales method’’ of accounting for its oil
and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids
sold to purchasers. A receivable or liability is recognized only to the extent that the Company has an
imbalance on a specific property greater than the expected remaining proved reserves.
Production Costs
Production costs, including compressor rental, pumpers’ salaries, saltwater disposal, ad valorem
taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses are
expensed as incurred and included in lease operating expense on the Consolidated Statement of
Operations.
Exploration Expenses
Exploration expenses include dry hole costs, lease extensions, delay rentals and geological and
geophysical costs.
Income Taxes
Following its IPO on July 29, 2013, the Company began recording a federal and state income tax
liability associated with its status as a corporation. No provision for federal income taxes was recorded
F-13
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
prior to the IPO because the taxable income or loss was includable in the income tax returns of the
individual partners and members. The Company is also subject to state income taxes. The State of
Texas includes in its tax system a franchise tax applicable to the Company and an accrual for franchise
taxes is included in the financial statements when appropriate.
Income taxes are accounted for under the asset and liability method, which requires recognition of
deferred tax assets and liabilities for the expected future tax consequences of events that have been
included in the financial statements. Under this method, deferred tax assets and liabilities are
determined based on the differences between the financial statements and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which differences are expected to be
recovered or settled pursuant to the provisions of ASC 740—Income Taxes. The effect of a change in
tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the
enactment date.
The Company records a valuation allowance if it is deemed more likely than not that all or a
portion of its deferred income tax assets will not be realized. In addition, income tax rules and
regulations are subject to interpretation and the application of those rules and regulations require
judgment by the Company and may be challenged by the taxation authorities. The Company follows
ASC 740-10-25, which requires the use of a two-step approach for recognizing and measuring tax
benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income
tax positions. Only tax positions that meet the more likely than not recognition threshold are
recognized. The Company’s policy is to include any interest and penalties recorded on uncertain tax
positions as a component of income tax expense. The Company’s unrecognized tax benefits or related
interest and penalties are immaterial.
Tax Receivable Agreement
In conjunction with the IPO, the Company entered into a Tax Receivable Agreement (‘‘TRA’’) with
JEH and the pre-IPO owners. Upon any exchange of JEH—Units and Class B common stock of the
Company held by JEH’s pre-IPO owners for Class A common stock of the Company, the TRA
provides for the payment by the Company, directly to such exchanging owners, of 85% of the amount
of cash savings in income or franchise taxes that the Company realizes as a result of (i) the tax basis
increases resulting from the exchange of JEH Units for shares of Class A common stock (or resulting
from a sale of JEH Units for cash) and (ii) imputed interest deemed to be paid by the Company as a
result of, and additional tax basis arising from, any payments the Company makes under the TRA. The
Company will retain the benefit of the remaining 15% of the cash savings. Liabilities under the TRA
will be recognized upon the exchange of shares. As of December 31, 2013, there have been no
exchanges and no liability is recorded on the Consolidated Balance Sheet.
Comprehensive Income
The Company has no elements of comprehensive income other than net income.
Statement of Cash Flows
The Company presents its cash flows using the indirect method.
F-14
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Related Party Transactions
In the years ended December 31, 2013, 2012 and 2011, the Company paid an annual
administration fee to Metalmark of $0.7 million. This amount was charged to expense. As a result of
the IPO, this fee is no longer payable to Metalmark.
On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with
Monarch Natural Gas, LLC, or Monarch, under which Monarch has the first right to gather the natural
gas the Company produces from the Chalker properties, process the NGLs from this natural gas
production and market the processed natural gas and extracted NGLs. Under the Monarch agreement,
the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch,
based on a set liquids recovery percentage, and the amount received from the sale of the residue gas,
after deducting a fixed volume for fuel, lost and unaccounted for gas. For the year ended December 31,
2013, the Company produced approximately 0.8 MMBoe of natural gas and NGLs from the Chalker
properties that became subject to the Monarch agreement. The initial term of the agreement runs for
10 years from the effective date of September 1, 2013. At the time the Company entered into the
agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of
Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company’s
outstanding equity interests and two of our directors, Howard I. Hoffen and Gregory D. Myers, are
managing directors of Metalmark Capital. In connection with the Company’s entering into the Monarch
agreement, Monarch issued to JEH equity interests in Monarch having a deemed value of $15 million.
JEH assigned $2.4 million of the Monarch equity interests to Jonny Jones, the Company’s chief
executive officer and chairman of the board, and reserved $2.6 million of the Monarch equity interests
to a benefit plan established for certain of the Company’s officers, including Mike McConnell, Robert
Brooks and Eric Niccum. The remaining $10 million of Monarch equity was distributed to certain of
the pre-IPO owners, which include Metalmark Capital, Wells Fargo, the Jones family entities, and
certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell, Robert
Brooks and Eric Niccum.
Stock Compensation
JEH implemented a management incentive plan effective January 1, 2010, that provided
membership-interest awards in JEH to members of senior management (‘‘management units’’). The
management unit grants awarded prior to the initial filing of the registration statement in March 2013
had a dual vesting schedule. Sixty percent of the units awarded vested in five equal annual installments,
with the remaining 40% vesting upon a company restructuring event, including the IPO. All grants
awarded after the initial registration statement have a single vesting structure of five equal annual
installments and were valued at the IPO price, adjusted for equivalent shares. Both the vested and
unvested management units were converted into JEH Units and shares of Class B common stock at the
IPO date. At December 31, 2013, there were 457,150 unvested JEH Units and shares of Class B
common stock that will become convertible into a like number of shares of Class A common stock
upon vesting.
Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan, established in conjunction with the
Company’s IPO, the Company reserved 3,850,000 shares of Class A common stock for director and
employee stock-based compensation awards. As of December 31, 2013 no such awards had been issued
or granted to any of the Company’s employees.
F-15
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
On September 4, 2013, the Company granted each of the four outside members of the Board of
Directors 6,645 shares of restricted Class A common stock under the Jones Energy, Inc. 2013 Omnibus
Incentive Plan. The fair value of the restricted stock grants was based on the value of the Company’s
Class A common stock on the date of grant and is expensed on a straight-line basis over the one-year
vesting period.
Refer to Note 7, ‘‘Stock-based Compensation,’’ for additional information regarding the
management units and restricted stock awards.
Business Combinations
For acquisitions of working interests that are accounted for as business combinations, the results of
operations are included in the Consolidated Statement of Operations from the date of acquisition.
Purchase prices are allocated to assets acquired based on their estimated fair values at the time of
acquisition. Fair value is the price that would be received to sell an asset or would be paid to transfer a
liability in an orderly transaction between market participants at the measurement date. The fair value
measurement is based on the assumptions of market participants and not those of the reporting entity.
Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of oil
and natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis
based upon significant inputs including: 1) oil and gas prices, 2) projections of estimated quantities of
oil and natural gas reserves, including those classified as proved, probable and possible, 3) projections
of future rates of production, 4) timing and amount of future development and operating costs,
5) projected reserve recovery factors, and 6) weighted average cost of capital.
Recent Accounting Developments
The following recently issued accounting pronouncement has been adopted by the Company:
Offsetting Assets and Liabilities
In December 2011, the Financial Accounting Standards Board (‘‘FASB’’), issued authoritative
guidance requiring entities to disclose both gross and net information about instruments and
transactions eligible for offset arrangement. In January 2013, FASB issued an update to the previously
issued guidance with the purpose of clarifying the scope of the disclosures about the offsetting assets
and liabilities. The additional disclosures enable users of the financial statements to evaluate the effect
or potential effect of netting arrangements on an entity’s financial position. These disclosure
requirements are effective for interim and annual periods beginning after January 1, 2013. The
Company has provided all required disclosures for the periods presented as they pertain to its
commodity derivative instruments (see Note 4, ‘‘Fair Value Measurement’’). These disclosure
requirements did not affect the Company’s operating results, financial position, or cash flows.
3. Acquisition of Properties
On December 18, 2013, JEH closed on the purchase of certain oil and natural gas properties
located in Texas and western Oklahoma from Sabine Mid-Continent, LLC, for an adjusted purchase
price of $193.5 million (referred to herein as the ‘‘Sabine acquisition’’ or ‘‘Sabine’’), subject to
customary closing adjustments. The acquired assets include both producing properties and undeveloped
F-16
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
3. Acquisition of Properties (Continued)
acreage. The purchase was financed with borrowings under the senior secured credit facility. The
purchase price was allocated as follows:
(in thousands of dollars)
Oil and gas properties
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 39,596
154,724
(824)
Total purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$193,496
This acquisition qualified as a business combination under ASC 805. The valuation to determine
the fair value was principally based on the discounted cash flows of the producing and undeveloped
properties, including projected drilling and equipment costs, recoverable reserves, production streams,
future prices and operating costs, and risk-adjusted discount rates reflective of the current market. The
determination of fair value is dependent on factors as of the acquisition date and the final adjustments
to the purchase price, which when they occur, may result in an adjustment to the value of the acquired
properties reflected in the consolidated financial statements. Any such adjustment may be material.
In connection with the closing, approximately $24 million of the purchase price was placed in an
escrow account. This amount represented the allocated value of the Sabine properties that had
unresolved title defects claimed by JEH. In the event one or more title defects are not cured by Sabine,
the affected property will be reconveyed to Sabine and the Company will receive an amount of cash
from the escrow account equal to the allocated value of the reconveyed property. A corresponding
adjustment to the allocation of the Sabine purchase price will be made at such time.
The unaudited pro forma results presented below have been prepared to include the effect of the
Sabine acquisition on our results of operations for the year ended December 31, 2013. The unaudited
pro forma results do not purport to represent what our actual results of operations would have been if
the acquisition had been completed on January 1, 2013 or to project our results of operations for any
future date or period.
(in thousands of dollars)
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Post
Acquisition(1)
(unaudited)
$1,365
291
1,074
1,074
Year Ended
December 31,
2013
Pro Forma
(unaudited)
$308,773
229,648
79,125
45,778
(1) Represents revenues and expenses for the post acquisition period of December 18, 2013
to December 31, 2013 included in the Consolidated Statement of Operations.
On December 20, 2012, JEH acquired certain oil and natural gas properties located in Texas for a
purchase price of $251.9 million (referred to herein as the ‘‘Chalker acquisition’’ or ‘‘Chalker’’). The
acquired assets included both producing properties and undeveloped acreage. The purchase was
F-17
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
3. Acquisition of Properties (Continued)
financed with additional equity capital and borrowings under the senior secured credit facility. In the
second quarter of 2013, the Company made a final determination with the sellers as to the purchase
price adjustments resulting in a final purchase price of $253.5 million. The final purchase price was
allocated as follows:
(in thousands of dollars)
Oil and gas properties
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 71,264
182,493
(293)
Total purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$253,464
This acquisition qualified as a business combination under ASC 805. The valuation to determine
the fair value was principally based on the discounted cash flows of the producing and undeveloped
properties, including projected drilling and equipment costs, recoverable reserves, production streams,
future prices and operating costs, and risk-adjusted discount rates reflective of the current market.
The unaudited pro forma results presented below have been prepared to include the effect of the
Chalker acquisition on our results of operations for the year ended December 31, 2012. The unaudited
pro forma results do not purport to represent what our actual results of operations would have been if
the acquisition had been completed on January 1, 2012 or to project our results of operations for any
future date or period.
(in thousands of dollars)
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended
December 31,
2012
Pro Forma
(unaudited)
$194,685
161,053
33,632
25,713
On April 14, 2011, Jones Energy acquired certain oil and natural gas properties located in
Oklahoma for a purchase price of $154.1 million. The acquisition included both producing and
undeveloped properties. The purchase was financed with additional borrowings under the senior
secured credit facility. The purchase price was allocated as follows:
(in thousands of dollars)
Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$154,225
(167)
Total purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$154,058
This acquisition qualified as a business combination under ASC 805. The Company recorded a
total fair value of $180.3 million ($154.1 million for producing properties and $26.2 million for
undeveloped property). The total resulted in a bargain purchase gain of $26.2 million, which was
recorded in the Consolidated Statement of Operations. The valuation to determine the fair value was
F-18
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
3. Acquisition of Properties (Continued)
principally based on the discounted cash flows of the both the producing and undeveloped properties,
including projected drilling and equipment costs, recoverable reserves, production streams, future prices
and operating costs, and risk-adjusted discount rates reflective of the current market. The recognized
gain was the difference between the net fair value and the consideration paid the seller.
Management believes the bargain purchase gain resulted from the fact that the seller, who retained
a 50% ownership interest in the undeveloped properties, benefitted from the Company’s available
liquidity that would enable accelerated development of the prospect.
The following income statement line items present the pro forma results as if these properties had
been acquired on January 1, 2010:
(in thousands of dollars)
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended
December 31,
2011
Pro Forma
(unaudited)
$176,884
150,197
26,687
62,408
4. Fair Value Measurement
Fair Value of Financial Instruments
The Company determines fair value amounts using available market information and appropriate
valuation methodologies. Fair value is the price that would be received to sell an asset or would be
paid to transfer a liability in an orderly transaction between market participants at the measurement
date. Considerable judgment is required in interpreting market data to develop the estimates of fair
value. The use of different market assumptions and/or estimation methods may have a material effect
on the estimated fair value amounts.
The Company enters into a variety of derivative financial instruments, which may include
over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The
Company utilizes valuation techniques that maximize the use of observable inputs, where available. If
listed market prices or quotes are not published, fair value is determined based upon a market quote,
adjusted by other market-based or independently sourced market data, such as trading volume,
historical commodity volatility, and counterparty-specific considerations. These adjustments may include
amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.
Counterparty credit valuation adjustments are necessary when the market price of an instrument is
not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market
quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an
adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value
of the instrument. The Company currently has all derivative positions placed and held by members of
its lending group, which have strong credit quality.
F-19
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
Liquidity valuation adjustments are necessary when the Company is not able to observe a recent
market price for financial instruments that trade in less active markets. Exchange traded contracts are
valued at market value without making any additional valuation adjustments; therefore, no liquidity
reserve is applied.
Valuation Hierarchy
Fair value measurements are grouped into a three-level valuation hierarchy. The valuation
hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the
measurement date. A financial instrument’s categorization within the hierarchy is based upon the input
that requires the highest degree of judgment in the determination of the instrument’s fair value. The
three levels are defined as follows:
Level 1 Pricing inputs are based on published prices in active markets for identical
assets or liabilities as of the reporting date. The Company does not classify
any of its financial instruments in Level 1.
Level 2 Pricing inputs include quoted prices for similar assets and liabilities in
active markets, and inputs that are observable for the asset or liability,
either directly or indirectly, as of the reporting date. Contracts that are not
traded on a recognized exchange or are tied to pricing transactions for
which forward curve pricing is readily available are classified as
Level 2 instruments. These include natural gas, crude oil and some natural
gas liquids price swaps and natural gas basis swaps.
Level 3 Pricing inputs include significant inputs that are generally unobservable
from objective sources. The Company classifies natural gas liquid swaps
and basis swaps for which future pricing is not readily available as
Level 3. The Company obtains estimates from independent third parties
for its open positions and subjects those to the credit adjustment criteria
described above.
F-20
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
The financial instruments carried at fair value as of December 31, 2013 and 2012, by consolidated
balance sheet caption and by valuation hierarchy, as described above are as follows:
(in thousands of dollars)
Commodity Price Hedges
Current assets . . . . . . . . . . . . . . . . . . . . . . .
Long-term assets . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . .
Long-term liabilities . . . . . . . . . . . . . . . . . . .
(in thousands of dollars)
Commodity Price Hedges
Current assets . . . . . . . . . . . . . . . . . . . . . . .
Long-term assets . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . .
Long-term liabilities . . . . . . . . . . . . . . . . . . .
December 31, 2013
Fair Value Measurements Using
(Level 1)
(Level 2)
(Level 3)
Total
$—
—
—
—
$ 8,837
25,967
10,188
—
$ — $ 8,837
25,398
10,664
190
(569)
476
190
December 31, 2012
Fair Value Measurements Using
(Level 1)
(Level 2)
(Level 3)
Total
$—
—
—
—
$17,648
24,756
2,992
6,739
$ — $17,648
25,199
4,035
7,657
443
1,043
918
The following table represents quantitative information about Level 3 inputs used in the fair value
measurement of the Company’s commodity derivative contracts as of December 31, 2013.
Commodity Price Hedges
Fair Value
Valuation Technique
Unobservable Input
Range
Natural gas liquid swaps . . .
$(1,235) Use a discounted cash flow
Natural gas liquid futures $9.24 - $83.06 per barrel
Quantitative Information About Level 3 Fair Value Measurements
approach using inputs including
forward price statements from
counterparties
Significant increases/decreases in natural gas liquid futures in isolation would result in a
significantly lower/higher fair value measurement. The following table presents the changes in the
Level 3 financial instruments for the years ended December 31, 2013 and 2012. Changes in fair value
of Level 3 instruments represent changes in gains and losses for the periods that are reported in other
income (expense). New contracts entered into during the year are generally entered into at no cost with
F-21
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
changes in fair value from the date of agreement representing the entire fair value of the instrument.
Transfers between levels are evaluated at the end of the reporting period.
(in thousands of dollars)
Balance at January 1, 2012, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to Level 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2012, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to Level 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(2,083)
(2,352)
—
2,370
834
(288)
(1,519)
(1,095)
(210)
(753)
2,342
Balance at December 31, 2013, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(1,235)
Transfers from Level 3 to Level 2 represent all of the Company’s natural gas basis swaps for which
observable forward curve pricing information has become readily available. In 2012, transfers to
Level 3 represented natural gas liquid swaps or basis swaps that were classified as Level 2 in 2011 but
due to the unavailability of forward prices in 2012, were classified as Level 3 in 2012. The purchases
represent natural gas liquid swaps that the Company entered into in 2013 that do not have observable
forward curve pricing information.
Offsetting Assets and Liabilities
As of December 31, 2013, the counterparties to our commodity derivative contracts consisted of six
financial institutions. All of our counterparties or their affiliates are also lenders under our credit
facility. Therefore, we are not generally required to post additional collateral under our derivative
agreements.
Our derivative agreements contain set-off provisions that state that in the event of default or early
termination, any obligation owed by the defaulting party may be offset against any obligation owed to
the defaulting party.
F-22
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
We adopted the guidance requiring disclosure of both gross and net information about financial
instruments eligible for netting in the balance sheet under our derivative agreements. The following
table presents information about our commodity derivative contracts that are netted on our
Consolidated Balance Sheet as of December 31, 2013 and December 31, 2012:
Gross Amounts
of Recognized
Assets /
Liabilities
Gross
Amounts
Offset in the
Balance
Sheet
Net Amounts
of Assets /
Liabilities
Presented in
the Balance
Sheet
Gross Amounts
Not
Offset in the
Balance
Sheet
Net Amount
$ 38,071
(14,347)
$(6,035)
6,035
$ 32,036
(8,312)
$ 2,199
(2,542)
$ 34,235
(10,854)
$ 49,200
(17,928)
$(7,831)
7,831
$ 41,369
(10,097)
$ 1,478
(1,595)
$ 42,847
(11,692)
(in thousands of dollars)
December 31, 2013
Commodity derivative
contracts
Assets . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . .
December 31, 2012
Commodity derivative
contracts
Assets . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . .
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date
of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used
in the analysis of fair value of the oil and gas property acquired include the Company’s estimate of
future commodity prices, production costs, development expenditures, production, risk-adjusted
discount rates, and other relevant data. Additionally, fair value is used to determine the inception value
of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs
incurred historically for similar work, as well as estimates from independent third parties for costs that
would be incurred to restore leased property to the contractually stipulated condition. Additions to the
Company’s ARO represent a nonrecurring Level 3 measurement.
The Company reviews its proved oil and gas properties for impairment purposes by comparing the
expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost
of the asset. No significant impairment charges on the Company’s proved properties were recorded
during the year ended December 31, 2013. During 2012 and 2011, unamortized capitalized costs of
certain properties were higher than their expected undiscounted future cash flows due primarily to
downward reserve revisions, drilling of marginal or uneconomic wells, or development dry holes in
certain producing fields. As a result, the Company recorded charges of $18.8 million and $19.8 million
during the years ended December 31, 2012 and 2011, respectively.
Additionally, the Company reviews its unproved properties for indicators of impairment based on
the Company’s current exploration plans. In the fourth quarter of 2013, the Company recorded an
impairment charge of $14.4 million related to the Southridge properties. As the Company did not drill
the required number of wells by October 31, 2013 necessary to keep its joint development agreement
with Southridge in effect, the Company lost its right to the undeveloped acreage and associated
reserves. The Company incurred no impairment charges related to its unproved properties in 2012. In
F-23
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
2011, the Company incurred a $12.2 million impairment charge related to its unproven properties in
fields which were not expected to produce natural gas with a sufficiently high liquid content. With low
natural gas prices during that period, the lack of natural gas liquids reduced the economic return of
those fields and as a result, the Company had no intentions to continue development of those fields.
Impairment charges are recorded on the Consolidated Statement of Operations. Significant
assumptions associated with the calculation of future cash flows used in the impairment analysis include
the Company’s estimate of future commodity prices, production costs, development expenditures,
production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas
properties used in estimating impairment represents a nonrecurring Level 3 measurement.
5. Derivative Instruments and Hedging Activities
The Company had various commodity derivatives in place to offset uncertain price fluctuations
that could affect its future operations as of December 31, 2013 and 2012, as follows:
Hedging Positions
December 31, 2013
Low
High
Weighted
Average
Final
Expiration
Oil swaps . . . . . . . . . . . . . Exercise price
Barrels per month
Natural gas swaps . . . . . . . Exercise price
mmbtu per month
$
81.70
29,000
$
102.84
161,613
$
3.88
510,000
$
6.90
1,290,000
$
$
89.03
96,149 December 2017
4.26
830,275 December 2017
Basis swaps . . . . . . . . . . . Contract differential
$
(0.43) $
(0.11) $
(0.34)
mmbtu per month
320,000
690,000
467,037 March 2016
Natural gas liquids swaps . Exercise price
Barrels per month
$
6.72
2,000
$
95.24
118,000
$
32.98
46,646 December 2017
December 31, 2012
Low
High
Weighted
Average
Final
Expiration
Oil swaps . . . . . . . . . . . . . Exercise price
Barrels per month
Natural gas swaps . . . . . . . Exercise price
mmbtu per month
$
81.00
24,000
$
104.45
143,116
$
3.52
430,000
$
6.90
1,110,000
$
$
89.60
89,323 December 2017
4.96
767,053 December 2017
Basis swaps . . . . . . . . . . . Contract differential
$
(0.65) $
(0.03) $
(0.31)
mmbtu per month
320,000
850,000
484,615 March 2016
Natural gas liquids swaps . Exercise price
Barrels per month
$
6.72
2,000
$
97.13
144,973
$
33.81
55,616 December 2017
F-24
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
5. Derivative Instruments and Hedging Activities (Continued)
The Company recognized a net loss on derivative instruments of $2.6 million for the year ended
December 31, 2013 and net gains of $16.7 million and $34.5 million for the years ended December 31,
2012 and 2011, respectively.
6. Long-Term Debt
The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo
Bank N.A, the Senior Secured Revolving Credit Facility (the ‘‘Revolver’’) and the Second Lien Term
Loan (the ‘‘Term Loan’’) which were subsequently amended on November 18, 2011, November 5, 2012,
December 20, 2012, June 12, 2013, December 18, 2013 and January 29, 2014. In connection with the
November 2012 amendment, the maturity date of the Revolver was extended to November 5, 2017 and
the maturity date of the Term loan was extended to May 5, 2018. In connection with the June 2013
amendment, the borrowing base on the Revolver was increased to $500.0 million and subsequently
increased to $575.0 million on December 18, 2013 in conjunction with the Sabine acquisition. The
Company’s oil and gas properties are pledged as collateral against these credit agreements.
Terms of the Revolver require the Company to pay interest on the loan on the earlier of the
London InterBank Offered Rate (LIBOR) tranche maturity date or three months, with the entire
principal and interest due on the loan maturity date. Borrowings may be drawn on the principal
amount up to the maximum available credit amount. Interest on the Revolver is calculated at a base
rate (LIBOR or prime), plus a margin of 0.50% to 2.50% based on the actual amount borrowed
compared to the borrowing base amount and the base rate selected. For the year ended December 31,
2013, the average interest rate under the Revolver was 3.01% on an average outstanding balance of
$384.9 million. For the year ended December 31, 2012, the average interest rate under the Revolver
was 3.30% on an average outstanding balance of $306.8 million.
Terms of the Term Loan require the Company to pay interest on the loan every three months with
the principal and interest due on the loan maturity date of May 5, 2018. Interest on the Term Loan is
calculated at a base rate (LIBOR, prime, or federal funds), plus a margin of 6% to 7% based on the
base rate selected. As of December 31, 2013, the average interest rate was 9.19% on an average
outstanding balance of $160.0 million. As of December 31, 2012, the average interest rate was 9.16%
on an average outstanding balance of $121.3 million.
Total interest and commitment fees under the two facilities were $27.0 million, $21.2 million and
$18.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.
In connection with the IPO, the Company used the net proceeds to repay outstanding borrowings
under the Revolver of $167.0 million.
The Revolver and Term Loans are categorized as Level 3 in the valuation hierarchy as the debt is
not publicly traded and no observable market exists to determine the fair value; however, the carrying
value of the Revolver and Term Loans approximate fair value, as they are subject to short-term floating
interest rates that approximate the rates available to the Company for those periods.
The Revolver and Term Loans include covenants that require, among other things, restrictions on
asset sales, distributions to members, and additional indebtedness, and the maintenance of certain
financial ratios, including leverage, proven reserves to debt, and current ratio. The Company was in
compliance with these covenants at December 31, 2013.
F-25
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
7. Stock-based Compensation
JEH granted membership-interest awards in JEH to members of senior management
(‘‘management units’’) under a management incentive plan prior to the IPO. These awards had various
vesting schedules, and a portion of the management units vested in a lump sum at the IPO date. Both
the vested and unvested management units were converted into JEH Units and shares of Class B
common stock at the IPO date. As of December 31, 2013, there were 457,150 unvested JEH Units and
shares of Class B common stock. The Units/shares will become convertible into a like number of shares
of Class A common stock upon vesting. The following table summarizes information related to the
Units/shares held by management:
Unvested at January 1, 2013 . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
JEH Units
710,767
911,654
(167,239)
(998,032)
Unvested at December 31, 2013 . . . . . . . . . . . . . . . .
457,150
Weighted Average
Grant Date Fair Value
per Share
$ 3.62
$15.00
$ 3.62
$ 9.96
$12.46
Stock compensation expense associated with the management units for the years ended
December 31, 2013, 2012 and 2011 was $10.7 million, $0.6 million and $1.1 million, respectively, and is
included in general and administrative expenses on the Company’s Consolidated Statement of
Operations.
On September 4, 2013, the Company granted restricted stock awards to non-employee members of
the Board of Directors. Each of the four directors was awarded 6,645 restricted shares of Class A
common stock, contingent on the director serving as a director of the Company for a one-year service
period from the date of grant. The fair value of the awards was based on the value of the Company’s
Class A common stock on the date of grant. The total value of the awards to the directors is as follows:
Restricted
Stock Awards
Weighted Average
Grant Date Fair Value
per Share
Unvested at January 1, 2013 . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested at December 31, 2013 . . . . . . . . . . . . . .
—
27
—
—
27
—
$15.05
—
—
$15.05
Stock compensation expense associated with the Board of Directors awards for the year ended
December 31, 2013 was $0.1 million and is included in general and administrative expenses on the
Company’s Consolidated Statement of Operations.
8. Earnings per Share
Basic earnings per share (‘‘EPS’’) is computed by dividing net income (loss) attributable to
controlling interests by the weighted-average number of shares of Class A common stock outstanding
during the period. Class B common stock is not included in the calculation of earnings per share
F-26
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
8. Earnings per Share (Continued)
because they are not participating securities and have no economic interest in the Company. Diluted
earnings per share takes into account the dilutive effect of potential common stock that could be issued
by the Company in conjunction with stock awards that have been granted to directors and employees.
On September 4, 2013 (the ‘‘grant date’’), the Company granted to its directors restricted shares of
Class A common stock, which vest on the first anniversary of the grant date. In accordance with
ASC 260, Earnings Per Share, awards of nonvested shares shall be considered outstanding as of the
grant date for purposes of computing diluted EPS even though their exercise is contingent upon
vesting. For the year ended December 31, 2013, the directors’ restricted shares of Class A common
stock were excluded from the diluted calculation, as their inclusion would have been anti-dilutive as the
Company was in a net loss position. The following is a calculation of the basic and diluted weighted-
average number of shares of Class A common stock outstanding and EPS for the year ended
December 31, 2013. Net income (loss) and the weighted average number of shares of Class A common
stock outstanding is based on the actual days in which the shares were outstanding for the period from
July 29, 2013, the closing date of the IPO, to December 31, 2013.
(in thousands, except per share data)
Income (numerator):
December 31, 2013
Net income (loss) attributable to controlling interests . . . . . . . . .
$(2,186)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock—
basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,500
Earnings (loss) per share:
Basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (0.17)
Anti-dilutive restricted shares of Class A common stock . . . . . . . . .
27
9. Monarch Investment
On May 7, 2013, the Company entered into a marketing agreement with Monarch Natural
Gas, LLC (‘‘Monarch’’), a company related through common ownership, for the sale to Monarch of
natural gas produced from certain properties. In connection with that agreement, Monarch issued to
the Company equity interests in its parent, Monarch Natural Gas Holdings, LLC, having an estimated
fair value of $15.0 million. Contemporaneous with the execution of the marketing agreement and the
issuance of the equity interests, the Company distributed 67% or $10 million of the Monarch equity
interests to the Company’s owners pro rata based on equity contributions and approximately 16% of
the interests to a member of management. The remaining approximately 17% of the equity interests
were reserved for distribution to management through an incentive plan. The Company recognized
$0.3 million of compensation expense during the year ended December 31, 2013 in connection with the
incentive plan. In addition, the Company recorded deferred revenue of $15.0 million which is being
amortized on an estimated units-of-production basis commencing in September 2013, the first month of
production sales to Monarch. The Company amortized $0.5 million of the deferred revenue balance
during the year ended December 31, 2013 and is recorded in other revenues on the Company’s
Consolidated Statement of Operations.
F-27
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
10. Commitments and Contingencies
Lease obligations
The Company leases approximately 31,000 square feet of office space in Austin, TX under an
operating lease arrangement. Future minimum payments for noncancellable operating leases extending
beyond one year at December 31, 2013 are as follows:
(in thousands of dollars)
Years Ending December 31,
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 586
482
458
147
—
$1,673
Rent expense under operating leases was $0.8 million, $0.8 million and $0.7 million for the years
ended December 31, 2013, 2012 and 2011, respectively.
Litigation
The Company is subject to legal proceedings and claims that arise in the ordinary course of its
business. The Company believes that the final disposition of such current matters will not have a
material adverse effect on its financial position, results of operations, or liquidity.
11. Benefit Plans
The Company established a 401(k) tax-deferred savings plan (the ‘‘Plan’’) for the benefit of
employees. The Plan is a defined contribution plan and the Company may match a portion of employee
contributions. For the years ended December 31, 2013 and 2012, $0.3 million and $0.2 million were
contributed, respectively, to the Plan.
In 2013, the Company established a 409A tax-deferred savings plan for the benefit of key
employees. This plan is a defined contribution plan, and the Company may match a portion of
employee contributions. For the year ended December 31, 2013, the Company made a negligible
contribution to this plan.
12. Income Taxes
Following its IPO, the Company began recording a federal and state income tax liability associated
with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas
franchise tax as the Company’s taxable income or loss was includable in the income tax returns of the
individual partners and members.
The Company will recognize a tax liability on its share of pre-tax book income, exclusive of the
non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas
F-28
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
12. Income Taxes (Continued)
franchise tax expense. The following table summarizes the tax provision for the years ended
December 31, 2013, 2012 and 2011:
(in thousands of dollars)
Current tax expense
Year Ended December 31,
2013
2012
2011
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85
—
85
$ — $ —
—
—
—
—
Deferred tax expense (benefit)
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,260) —
473
1,104
Total deferred expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total tax expense (benefit)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(156)
(71)
473
473
Tax benefit attributable to controlling interests . . . . . . . . . . . . . . . . . . . . . . . .
Tax expense attributable to non-controlling interests . . . . . . . . . . . . . . . . . . . .
(1,223) —
473
1,152
—
173
173
173
—
173
Total tax expense (benefit)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(71) $473
$173
For the years ended December 31, 2012 and 2011, the reported taxes relate solely to the Texas
franchise tax liability of JEH.
A reconciliation of the Company’s provision for income taxes as reported and the amount
computed by multiplying income before taxes, less non-controlling interest, by the U.S. federal statutory
rate of 35%:
(in thousands of dollars)
Provision calculated at federal statutory income tax rate:
December 31, 2013
Net income before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statutory rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$22,334
35%
Income tax expense computed at statutory rate . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Non-controlling interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit attributable to controlling interests . . . . . . . . . . . . . . . . . . . .
State and local income taxes, net of federal benefit . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit attributable to controlling interests . . . . . . . . . . . . . . . . . . . . . . . .
Tax expense attributable to non-controlling interests . . . . . . . . . . . . . . . . . . . . . . .
7,817
(9,009)
(1,192)
(49)
18
(1,223)
1,152
Total income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(71)
For the years ended December 31, 2012 and 2011, the calculation is not applicable as the
Company was not subject to federal income taxes prior to the IPO.
F-29
Jones Energy, Inc.
Notes to Consolidated Financial Statements (Continued)
12. Income Taxes (Continued)
The Company is subject to federal, state and local income and franchise taxes. As such, deferred
income taxes result from temporary differences between the carrying amounts of assets and liabilities of
the Company for financial reporting purposes and the amounts used for income tax purposes. Deferred
tax assets and liabilities are measured using enacted tax rates in effect in the years in which those
temporary differences are expected to reverse.
Significant components of the Company’s deferred tax assets and deferred tax liabilities consisted
of the following:
(in thousands of dollars)
Deferred tax assets
As of December 31,
2013
2012
Investment in consolidated subsidiary JEH . . . . . . . . . . . . . . .
Net operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alternative minimum tax credits . . . . . . . . . . . . . . . . . . . . . . .
State deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
526
649
86
52
$ —
—
—
—
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,313
—
Deferred tax liabilities
State deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . .
3,093
3,093
1,936
1,936
Net deferred tax assets (liabilities) . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,780)
—
(1,936)
—
Net deferred tax assets (liabilities) . . . . . . . . . . . . . . . . . . . .
$(1,780) $(1,936)
The Company has a federal net operating loss carry-forward totaling $1.8 million and state net
operating loss carry-forward of $0.4 million, both expiring in 2033. No valuation allowance has been
recorded as management believes that there is sufficient future taxable income to fully utilize its
deferred tax assets. This future taxable income will arise from reversing temporary differences due to
the excess of the book carrying value of oil and gas properties over their corresponding tax basis. The
Company may elect to capitalize intangible drilling costs, rather than expensing these costs, in order to
prevent an operating loss carry-forward from expiring unused.
Separate federal and state income tax returns are filed for Jones Energy, Inc. and Jones Energy
Holdings, LLC. JEH’s Texas franchise tax returns are subject to audit for 2009, 2010, 2011, and 2012.
The tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which
the Company is subject. The Company is not currently under audit in any other major taxing
jurisdiction.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement
methodology for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. As of December 31, 2013 and December 31, 2012 there was no
material liability or expense for the periods then ended recorded for payments of interest and penalties
associated with uncertain tax positions or material unrecognized tax positions and the Company’s
unrecognized tax benefits were not material.
F-30
Jones Energy, Inc.
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Costs Incurred
Costs incurred for oil and gas property acquisitions, exploration and development for the last three
years are as follows:
(in thousands of dollars)
Property acquisitions:
2013
2012
2011
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement costs . . . . . . . . . . . . . . . . . . . . . .
$ 51,266
142,230
1,710
240,412
1,822
$ 69,725
182,200
356
125,493
662
$
—
168,480
780
156,628
418
Total costs incurred . . . . . . . . . . . . . . . . . . . . . .
$437,440
$378,436
$326,306
Capitalized Costs
Capitalized costs for our oil and gas properties consisted of the following at the end of each of the
following years:
(in thousands)
Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depletion and impairment . . . . . . . . . . . . . . .
2013
2012
$ 114,457
1,568,564
$ 137,254
1,127,285
1,683,021
(370,470)
1,264,539
(257,195)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,312,551
$1,007,344
Reserves
Users of this information should be aware that the process of estimating quantities of proved and
proved developed oil and gas reserves (including natural gas liquids) is very complex, requiring
significant subjective decisions in the evaluation of all available geological, engineering and economic
data for each reservoir. The data for a given reservoir also may change substantially over time as a
result of numerous factors, including additional development activity, evolving production history and
continual reassessment of the viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates may occur from time to time.
The following tables set forth the Company’s total proved reserves and the changes in the
Company’s total proved reserves. These reserve estimates are based in part on reports prepared by
Cawley, Gillespie & Associates, Inc. (‘‘Cawley Gillespie’’), independent petroleum engineers, utilizing
data compiled by us. In preparing its reports, Cawley Gillespie evaluated properties representing all of
the Company’s proved reserves at December 31, 2013, 2012 and 2011. The Company’s proved reserves
are located onshore in the United States. There are many uncertainties inherent in estimating proved
reserve quantities, and projecting future production rates and the timing of future development
expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of
properties with production history. Accordingly, these estimates are subject to change as additional
information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas
liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be
economically producible in future years from known oil and natural gas reservoirs under existing
F-31
economic conditions, operating methods and government regulations at the end of the respective years.
Proved developed reserves are those reserves expected to be recovered through existing wells with
existing equipment and operating methods.
Estimated Proved Reserves
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of minerals in place . . . . . . . . . . . . . . . . . . . .
Sales of minerals in place . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of minerals in place . . . . . . . . . . . . . . . . . . . .
Sales of minerals in place . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates . . . . . . . . . . . . . . . . . . .
Crude Oil
(MBbls)
NGL
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)(1)
5,991
2,419
(811)
378
(114)
(423)
7,440
286
(742)
6,056
(8)
(492)
9,953
7,881
(1,215)
18,182
(201)
6
108,634
50,310
(11,438)
117,489
(2,688)
(17,728)
34,606
244,579
1,766
(1,770)
5,799
(53)
(5,602)
11,727
(13,980)
36,842
(309)
(50,779)
34,050
18,685
(3,932)
38,142
(763)
(3,372)
82,810
4,007
(4,842)
17,995
(113)
(14,557)
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,540
34,746
228,080
85,300
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of minerals in place . . . . . . . . . . . . . . . . . . . .
Sales of minerals in place . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates . . . . . . . . . . . . . . . . . . .
3,786
(1,557)
3,275
—
(1,356)
5,710
(1,724)
4,418
—
(10,235)
39,799
(17,575)
35,023
583
(49,262)
16,129
(6,210)
13,530
97
(19,801)
December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16,688
32,915
236,648
89,045
Revision of previous estimates
For the year ended December 31, 2013, the Company had net negative revisions of 19,801 MBoe,
of which 15,518 MBoe was related to the expiration of the Company’s JDA with Southridge. The
remaining net negative revisions of 4,283 MBoe were due to a combination of production performance
in the Cleveland and Woodford, prices and other changes.
For the year ended December 31, 2012, the Company had net negative revisions of 14,557 MBoe
primarily due to the removal of certain proved undeveloped reserves in the Atoka formation,
production performance in the Woodford formation and decreased gas prices in the Cleveland.
For the year ended December 31, 2011, the Company had net negative revisions of 3,372 MBoe
primarily due to the removal of certain proved undeveloped reserves in the Granite Wash, Cleveland,
and Atoka formations due to decreased gas prices. This was partially offset by the addition of certain
F-32
proved undeveloped reserves in the more liquid-rich area of the Cleveland formation due to increased
oil prices.
Crude Oil
(MBbls)
NGL
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)(1)
Estimated Proved Reserves
December 31, 2011
Proved developed . . . . . . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . .
Total proved reserves . . . . . . . . . . . . .
December 31, 2012
Proved developed . . . . . . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . .
2,535
4,905
7,440
4,262
8,278
Total proved reserves . . . . . . . . . . . . .
12,540
December 31, 2013
Proved developed . . . . . . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . .
7,129
9,559
Total proved reserves . . . . . . . . . . . . .
16,688
14,020
20,586
34,606
16,320
18,426
34,746
19,101
13,814
32,915
110,433
134,146
244,579
110,956
117,124
228,080
139,623
97,025
236,648
34,961
47,849
82,810
39,075
46,225
85,300
49,501
39,544
89,045
(1) Barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil or natural gas liquids.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information was developed utilizing procedures prescribed by FASB Accounting
Standards Codification Topic 932, Extractive Industries—Oil and Gas (Topic 932). The ‘‘standardized
measure of discounted future net cash flows’’ should not be viewed as representative of the current
value of our proved oil and gas reserves. It and the other information contained in the following tables
may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the
Company or its performance.
In reviewing the information that follows, the following factors should be taken into account:
(cid:127) future costs and sales prices will probably differ from those required to be used in these
calculations;
(cid:127) actual production rates for future periods may vary significantly from the rates assumed in the
calculations;
(cid:127) future tax rates, deductions and credits are calculated under current laws, which may change in
future years;
(cid:127) a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil
and natural gas revenues.
Under the standardized measure, future cash inflows were estimated by using the average of the
historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month
periods ended December 31, 2013, 2012 and 2011. Future cash inflows do not reflect the impact of
open hedge positions. Future cash inflows were reduced by estimated future development and
production costs based on year-end costs in order to arrive at net cash flows. Use of a 10% discount
rate, first-day-of-the-month prices and year-end costs are required by ASC 932.
F-33
In general, management does not rely on the following information in making investment and
operating decisions. Such decisions are based upon a wide range of factors, including estimates of
probable as well as proved reserves and varying price and cost assumptions considered more
representative of a range of possible outcomes.
The standardized measure of discounted future net cash flows from the Company’s estimated
proved oil and natural gas reserves follows:
(in thousands)
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013
2012
2011
$3,213,718
$2,746,767
$ 3,279,260
Less related future:
Production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(734,974)
(549,343)
(129,497)
(612,054)
(529,692)
—
(648,035)
(556,302)
—
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% annual discount for estimated timing of cash flows . . . . . .
1,799,904
(859,395)
1,605,021
(823,001)
2,074,923
(1,159,116)
Standardized measure of discounted future net cash flows . . . . .
$ 940,509
$ 782,020
$
915,807
A summary of the changes in the standardized measure of discounted future net cash flows
applicable to proved natural gas and crude oil reserves follows:
(in thousands)
Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013
2012
2011
$ 782,020
$ 915,807
$ 354,507
Net change in sales and transfer prices, net of production expenses
Changes in estimated future development costs . . . . . . . . . . . . . . .
Sales and transfers of oil and gas produced during the period . . . .
Net change due to extensions and discoveries . . . . . . . . . . . . . . . .
Net change due to purchases of minerals in place . . . . . . . . . . . . .
Net change due to sales of minerals in place . . . . . . . . . . . . . . . . .
Net change due to revisions in quantity estimates . . . . . . . . . . . . .
Previously estimated development costs incurred during the period .
Net change in income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77,280
(9,706)
(224,739)
239,844
149,619
(337)
(168,438)
110,783
(76,965)
59,621
1,527
(336,855)
67,495
(119,931)
37,723
197,740
(1,578)
(144,901)
99,513
—
91,581
(24,574)
133,740
3,391
(139,600)
298,299
230,687
(10,969)
(48,425)
83,287
—
35,451
(24,561)
Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 940,509
$ 782,020
$ 915,807
F-34
Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the Company’s results of operations by quarter for the years ended
December 31, 2013 and 2012.
(in thousands except per share data)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to non-controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss attributable to controlling interests . . . . .
Basic and diluted earnings per share . . . . . . . . . .
First
Quarter
Second
Quarter
2013
Third
Quarter
Fourth
Quarter
Full
Year
$55,480
18,047
(1,452)
$64,526
20,251
48,417
$ 68,851
12,095
(15,483)
$ 70,312
5,359
(9,077)
$259,169
55,752
22,405
(14,623)
(860)
(0.07) $
$
(7,751)
(1,326)
(0.11) $
24,591
(2,186)
(0.17)
First
Quarter
Second
Quarter
2012
Third
Quarter
Fourth
Quarter
Full
Year
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . .
$42,797
12,989
15,323
$31,354
1,852
26,803
$ 31,935
(324)
(24,527)
$ 43,728
(9,677)
(20,678)
$149,814
4,840
(3,079)
Supplemental Quarterly Financial Information (Unaudited)
We identified an error in our previously issued financial statements which would have been
material to our fourth quarter of 2013 if recorded as an out of period adjustment in such period.
Therefore, we have revised our Supplemental Quarterly Financial Information for the quarters ended
March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013
and September 30, 2013 to reflect additional interest expense on obligations that are unrelated to our
credit agreements discussed in Note 6. These revisions had the effect of:
(cid:127) decreasing net income (loss) by $0.1 million, $0.1 million, $0.2 million, $0.2 million, $0.2 million,
$0.2 million, and $0.3 million for the quarters ended March 31, 2012, June 30, 2012,
September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013 and September 30,
2013, respectively;
(cid:127) decreasing net income (loss) attributable to non-controlling interests by $0.2 million, for each of
the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013; and
(cid:127) decreasing net loss attributable to controlling interests by $39 thousand for the quarter ended
September 30, 2013.
We have determined that these errors are not material to any of our previously issued interim or
annual consolidated financial statements, therefore, no restatements have been made to the 2013
quarterly financial statements included in our previously filed Form 10-Qs for this matter. Additionally,
revisions to the three month period ended March 31, 2013, the three and six month periods ended
June 30, 2013 and the three and nine month periods ended September 30, 2013 will be made when
they are next filed in the Company’s quarterly financial statements on Form 10-Q for the quarters
ending March 31, 2014, June 30, 2014 and September 30, 2014, respectively.
F-35
FORWARD-LOOKING STATEMENT:
This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts,
included in this annual report that address activities, events or developments that the Company expects, believes or
anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the
foregoing, forward-looking statements contained in this annual report specifically include the expectations of plans,
strategies, objectives and anticipated operating results of the Company, including guidance regarding the Company’s
drilling program and ability to achieve favorable pricing for future acquisitions. These statements are based on certain
assumptions made by the Company based on management’s experience and perception of historical trends, current
conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject
to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may
cause actual results to differ materially from those implied or expressed by the forward-looking statements and are
described in further detail in the Company’s Annual Report on Form 10-K. Any forward-looking statement speaks
only as of the date on which such statement is made and the Company undertakes no obligation to correct or update
any forward-looking statement, whether as a result of new information, future events or otherwise, except as required
by applicable law.
MANAGEMENT:
Jonny Jones, Founder, Chairman &
Chief Executive Officer
Mike S. McConnell, Director & President
Robert J. Brooks, Executive Vice President &
Chief Financial Officer
Eric Niccum, Executive Vice President &
Chief Operating Officer
Jody Crook, Sr. Vice President – Acquisitions
Kristel Franklin, Sr. Vice President – Assets
Hal Hawthorne, Sr. Vice President – New Ventures
Stephen Roberts, Sr. Vice President – Drilling &
Completions
Todd Wehner, Sr. Vice President & Chief
Accounting Officer
BOARD OF DIRECTORS:
Jonny Jones, Chairman
Alan D. Bell, Director
Howard I. Hoffen, Director
Mike S. McConnell, Director
Gregory D. Myers, Director
Hal Washburn, Director
CORPORATE HEADQUARTERS:
Jones Energy, Inc.
807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
Phone: 512.328.2953
Fax: 512.328.5394
TRANSFER AGENT:
American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
www.amstock.com
STOCK EXCHANGE:
Common stock traded on the New York Stock
Exchange under the symbol: JONE
FORM 10-K:
For an additional copy of the Annual Report
on Form 10-K, please contact:
Jones Energy, Inc.
Investor Relations Department
Phone: 512.328.2953
Email: ir@jonesenergy.com
WEBSITE ADDRESS:
www.jonesenergy.com
ANNUAL MEETING:
The Annual Meeting for Jones Energy, Inc.
shareholders will be held at our corporate
headquarters in Austin, Texas on May 22, 2014.
J O N E S E N E R g Y , I N C .
8 0 7 l a s c i m a s p a r k w a y , s u i t e 3 5 0
a u s t i n , t e x a s 7 8 7 4 6