expertise c r e at e s
c r e at e s opportunities
2 0 1 4 A N N U A L R E P O R T
J o n e s e n e r g y 2 0 1 4 A N N U A L R E P O R T
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4/6/15 2:28 PM
ABOUT JONES ENERGY
Jones Energy, Inc. (NYSE: JONE) is an Austin, Texas–based independent oil and gas company engaged in the development,
production, and acquisition of oil and natural gas properties in the Anadarko and Arkoma basins of Texas and Oklahoma.
We have grown rapidly by leveraging our horizontal drilling expertise and low cost operations to develop our inventory.
OPERATIONS OVERVIEW
a N a D a r K O B a s I N
a r K O M a B a s I N
O K
KEY FORMATION:
Cleveland
KEY FORMATION:
Woodford
T X
AUSTIN
GROSS DRILLING LOCATIONS:
GROSS DRILLING LOCATIONS:
1,594
777
NET DRILLING LOCATIONS:
NET DRILLING LOCATIONS:
1,001
85
LEASED ACRES:
LEASED ACRES:
162,580
17,292
DAILY PRODUCTION:
DAILY PRODUCTION:
17.0 MBoe/d
4.0 MBoe/d
TOTAL PROVED RESERVES
DAILY PRODUCTION
GROSS ACREAGE
GROSS DRILLING LOCATIONS
115.3
MMBOE
23,216
BOE/D
218,015
2,765
43482cvr.indd 2
D E A R fellow S H A R E H O L D E R S :
A lot has changed in the oil and gas industry since I wrote to you
this time last year. As always, the future is uncertain and no one has a
crystal ball. But this I know to be true: Experience is an irreplaceable
asset, especially in turbulent times. After all, experience is necessary
to develop expertise, and expertise creates opportunities.
This time last year, Jones Energy was still a newly public company.
But we were not new to oil and gas. I founded Jones Energy as a
private E& P company 26 years ago in continuation of my family’s
long tradition in the oil and gas business.
LETTER FROM JONNY JONES
Founder, Chairman, & CEO
43482nar.indd 1
4/1/15 11:16 PM
2 0 1 4 A N N U A L R E P O R T
01
A L E T T E R F R O M J O N N Y J O N E S
I know what you’re thinking: “So what?
Yes, you have experience, but what does
that really mean for me today?”
It means that we have been here before. We are ready for this.
We understand that volatile commodity prices are an inevitable reality
in the oil and gas business. In fact, some of the greatest opportunities we
have seen as a company have been born out of an industry downturn.
When there is uncertainty and a lack of predictability, maintaining
flexibility is key. We have made it a point to be flexible, both from
an operational and a financial perspective.
We do not have long-term contracts with our rig providers or other
vendors. This allowed us to drop from 11 active rigs in the fall of 2014
to just 3 active rigs by the end of January 2015. We also have the ability
to add rigs as drilling and completion costs come down even further and
margins improve. Although it may sound counterintuitive, being the low-
cost operator means that our costs are the first to drop. Being
best-in-class where we operate gives us leverage when negotiating with
our partners and vendors — they know the lowest cost operator will
also be one of the first ones back in the game as soon as margins return.
Our extensive hedge program provides us with significant financial
flexibility, helping to secure our cash flow amidst an uncertain
commodity price environment. We have hedged 85% of our estimated
oil and gas production through 2016 at approximately $85 per barrel
and $4.50 per Mcf. A large portion of our estimated 2015 natural
gas liquids production is hedged as well. Our hedge position gives us
margin visibility. It allows us to focus on executing our 2015 operating
plan, instead of trying to react to commodity prices.
Hedging has been a foundation of Jones Energy since I started
the company 26 years ago. We believe that if a well is good enough to
drill, it is prudent to lock in the return with hedges. We will continue
to hedge, even if at lower commodity price levels. The key to an effective
hedging program is putting hedges in place, dutifully and methodically,
regardless of our view on the outlook for commodity prices. We continue
to believe that taking price risk off the table, even in a lower price
environment, is the right way to run our business.
In addition, earlier this year, we raised approximately $375 million
in gross proceeds through three transactions: a private placement of
$250 million in senior notes, a registered direct offering of $50 million
of common stock, and a $77 million public offering of common stock.
These transactions significantly enhanced our liquidity and solidified
02
J O N E S E N E R G Y
h e d g e d for s u c c e s s
Jones has a strong hedge position that
mitigates the risk of continued commodity
price declines. In the chart below, you can
observe how even if oil prices decline to
$10 per barrel and gas prices to $1 per
Mcf, our projected 2015 revenue only
declines by approximately 5%.
HEDGING IMPACT ON PROJECTED 2015 REVENUE
uNhedged ReVeNue
hedge gAIN
~5%
CHANGE IN TOTAL
REVENUE DUE
TO HEDGES
e
u
N
e
V
e
R
d
e
T
c
e
J
O
R
P
100%
80%
60%
40%
20%
0%
$60 OIL
$3.25 gAs
$30 OIL
$2 gAs
$10 OIL
$1 gAs
43482nar.indd 2
4/6/15 2:43 PM
VA LU E creation
We will do our best to make decisions that maximize value for our
shareholders — well beyond the current commodity environment —
while staying true to our values and tradition.
43482nar.indd 3
4/1/15 11:16 PM
2 0 1 4 A N N U A L R E P O R T
03
A L E T T E R F R O M J O N N Y J O N E S
PV-10 OF PROVED RESERVES
($ IN MILLIONS)
PROVED OIL RESERVES
(MMBOE)
EBITDAX
($ IN MILLIONS)
AVERAGE DAILY PRODUCTION
(MBOE/D)
8
2
47%
CAGR
7
1
3
1
39%
CAGR
2
0
5
,
1
7
1
0
,
1
2
8
7
1,600
1,200
800
400
0
30
25
20
15
10
5
0
49%
CAGR
1
0
3
5
0
2
6
3
1
325
260
195
130
65
0
25
20
15
10
5
0
33%
CAGR
3
2
7
1
3
1
2
1
0
2
3
1
0
2
4
1
0
2
2
1
0
2
3
1
0
2
4
1
0
2
2
1
0
2
3
1
0
2
4
1
0
2
2
1
0
2
3
1
0
2
4
1
0
2
our balance sheet. From our past experience, we know this to be
increased frack density in our core Cleveland play. In 2014, we grew
true — organizations with the liquidity to capitalize on opportunities
the PV-10 value of our proved reserves by 48%, driven by a 30%
have a significant competitive advantage. With our recent capital raises,
increase in total proved reserves and a 65% increase in proved oil
we believe the company is in a solid position financially, which allows
reserves. We also grew EBITDAX by 47% and production by
us to be opportunistic.
35% — impressive growth by any standard.
Overall, 2014 was a year of many
accomplishments for Jones Energy.
We made some big strides — actions
that I believe will benefit us in 2015
and beyond. Please allow me to
review our key accomplishments.
SIGNIFICANT VALUE CREATION
2014 was a year of significant growth in proved reserves, production
and EBITDAX. This was a direct result of our active drilling program,
a very successful leasing program, and the oil uplift achieved with
OIL UPLIFT — A TRUE PARADIGM SHIFT IN A MATURE PLAY
When we began drilling horizontal wells in the Cleveland in 2004,
we believed that the Cleveland was a natural gas play. Today, we
know the Cleveland is an oil play.
What changed?
Bolstered by our experience from drilling over 400 Cleveland
horizontal wells and by major improvements in completion technology,
we have found the primary driver of oil production in the Cleveland
to be the number of frack stages. Or to put it simply, for a Cleveland
well, more frack stages equates to more oil production.
04
J O N E S E N E R G Y
43482nar.indd 4
4/1/15 11:16 PM
Our ability to employ an increased number of frack stages has resulted
in a greater than 30% increase in oil production from our Cleveland
wells. This oil uplift has resulted in a meaningful increase in value in
our Cleveland play.
ORGANIC INVENTORY GROWTH THROUGH LEASING
Last year, we added more than 21,000 net acres to our portfolio
through leasing. This allowed us to replace all of the Cleveland
locations we drilled in 2014. It also provides us with additional
opportunities to drill in formations both above and below the
Cleveland in the future. All of this was acquired at a price of
approximately $1,300 per net acre, which is well below the lease
prices being paid by many of our competitors in other regions.
In 2015, we will execute our
operating plan, focusing on our core
competencies. Below, I outline our
key directives for 2015.
STICKING TO OUR BREAD AND BUTTER
We will use all that we have learned from over 25 years of experience
in the Anadarko Basin, and apply it to what we do best — drilling
Cleveland wells. We plan to allocate the majority of our capital in
2015 to drilling Cleveland wells, utilizing a tried and true, open-hole
completion method. We have completed hundreds of Cleveland
wells using the open-hole completion technology, and believe this
completion technique will allow us to achieve the optimal number of
frack stages at the lowest possible cost. We continue to see significant
opportunity within our footprint in the Anadarko Basin beyond
just the Cleveland play, but believe the prudent choice in the current
commodity environment is to focus on our core competency —
being a best-in-class operator in the Cleveland.
MAINTAINING OPERATIONAL FLEXIBILITY
We will ramp rig activity up or down as we see fit and as dictated by
our operating margins. We will not grow simply for growth’s sake,
but will only allocate capital to projects when and if we believe it is
prudent and profitable to do so.
MAXIMIZING RETURNS THROUGH COST MANAGEMENT
We will continue to focus relentlessly on maintaining our low cost
operations, which is paramount to achieving a competitive advantage
in our industry. We have already seen a material reduction in operating
costs since December 2014, and we will continue to work with our
partners and vendors to achieve additional cost improvements.
43482nar.indd 5
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2 0 1 4 A N N U A L R E P O R T
05
O P E R AT I O N A L flexibility
We will ramp activity as we see fit and as dictated
by our operating margins.
06
J O N E S E N E R G Y
43482nar.indd 6
4/1/15 11:17 PM
A L E T T E R F R O M J O N N Y J O N E S
PREPARING FOR MARkET OPPORTUNITIES
I have always said that success is achieved when hard work meets
opportunity. We cannot predict what opportunities may come our
way in 2015, but we will do our best to be ready for any opportunity,
whether it involves acquisitions, joint ventures, or organic growth.
Focusing on costs, exercising patience, and allocating capital
in a purposeful and deliberate way will drive our success in 2015.
In closing, I would like to thank you for your continued support and
belief in Jones Energy. We are off to a great start in 2015, and I believe
we are in excellent position to execute on our operating plan.
Having been in the business for 26 years, we know by now that
commodity prices go up and down — after all, the oil and gas industry
is cyclical. But at Jones Energy, we also know that we must focus on what
we can control. We must do our best to make decisions that maximize
value for our shareholders — well beyond the current commodity
environment — while staying true to our values and tradition.
Yours truly,
J O N N Y J O N e s
Founder, Chairman, & CEO
Jones Energy
I M P R e s s I V e g R O W T h
by A N Y s TA N d A R d
In 2014, we grew the PV-10 value of our
proved reserves by 48%, driven by a 30%
increase in total proved reserves and a 65%
increase in proved oil reserves. We also
grew EBITDAX by 47% and production
by 35%.
EBITDAX
($ IN MILLIONS)
1
0
3
3
2
47%
GROWTH
5
0
2
325
260
195
130
65
0
3
1
0
2
4
1
0
2
AVERAGE DAILY PRODUCTION
(MBOE/D)
25
20
15
10
5
0
35%
GROWTH
7
1
3
1
0
2
4
1
0
2
43482nar.indd 7
4/6/15 2:43 PM
2 0 1 4 A N N U A L R E P O R T
07
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 (loss) on sales of assets
Other income (expense), net
Income (loss) before income tax
INCOME TAX PROVISION (BENEFIT)
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,
2014
2013
2012
$ 378,401
$ 258,063
$ 148,967
2,196
380,597
1,106
259,169
43,843
18,094
3,453
181,669
-
770
25,763
273,592
107,005
(46,726)
189,641
297
143,212
250,217
26,074
224,143
183,275
27,781
12,865
1,710
114,136
14,415
608
31,902
203,417
55,752
(30,774)
(2,566)
(78)
(33,418)
22,334
(71)
22,405
24,591
847
149,814
23,097
5,583
356
80,709
18,821
533
15,875
144,974
4,840
(25,292)
16,684
1,162
(7,446)
(2,606)
473
(3,079)
-
$ 40,868
$
(2,186)
$ (3,079)
$ 64,205
$ 54,792
$
29,411
$ 301,393
$ 204,997
$
135,741
8.5
115.3
6.2
89.0
4.9
85.3
(1)
(2)
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.
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.
08
J O N E S E N E R G Y
43482nar.indd 8
4/1/15 11:17 PM
form 1 0 - K
J O N E S E N E R G Y
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(cid:3) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2014
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:3) No (cid:2)
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:3) No (cid:2)
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:2) No (cid:3)
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:2) No (cid:3)
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:2)
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:3)
Accelerated filer (cid:2)
Smaller reporting company (cid:3)
Non-accelerated filer (cid:3)
(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:3) No (cid:2)
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed
as of June 30, 2014 (the last business day of the Registrant’s most recently completed second fiscal quarter) based on the
closing price of the Class A common stock on the New York Stock Exchange was $256 million.
There were 25,208,402 and 36,422,660 shares of the registrant’s Class A and Class B common stock, respectively,
outstanding on February 27, 2015.
Portions of the registrant’s definitive proxy statement for the 2015 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
JONES ENERGY, INC.
TABLE OF CONTENTS
PART 1
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . .
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . .
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . .
Item 14. Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statement Schedules
Page(s)
3
30
53
53
53
53
54
56
60
78
80
80
80
82
82
82
82
82
82
83
87
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
i
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. When used in this
Annual Report, the words ‘‘could,’’ ‘‘should,’’ ‘‘will,’’ ‘‘may,’’ ‘‘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:
• business strategy;
• estimated current and future net reserves and the present value thereof;
• drilling and completion of wells including our identified drilling locations;
• cash flows and liquidity;
• financial strategy, budget, projections and operating results;
• the timing, extent and duration of changes in, and level of volatility of, prices for oil, natural gas
and NGLs;
• customers’ elections to reject ethane and include it as part of the natural gas stream;
• timing and amount of future production of oil and natural gas;
• availability and cost of drilling, completion and production equipment;
• availability and cost of oilfield labor;
• the amount, nature and timing of capital expenditures, including future development costs;
• ability to fund our 2015 capital expenditure budget;
• availability and terms of capital;
• development results from our identified drilling locations;
• ability to generate returns and pursue opportunities;
• marketing of oil, natural gas and NGLs;
• property acquisitions and dispositions;
• the availability, cost and terms of, and competition for mineral leases and other permits and
rights-of-way and our ability to maintain mineral leases;
• costs of developing our properties and conducting other operations;
• general economic conditions, including the levels of supply and demand for oil, natural gas and
NGLs, and the commodity price environment;
• competitive conditions in our industry;
• effectiveness and extent of our risk management activities;
1
• estimates of future potential impairments;
• environmental and endangered species regulations and liabilities;
• counterparty credit risk;
• the extent and effect of any hedging activities engaged in by us;
• the impact of, and changes in, governmental regulation of the oil and natural gas industry,
including tax laws and regulations, environmental, health and safety laws and regulations, and
laws and regulations with respect to derivatives and hedging activities;
• developments in oil-producing and natural gas-producing countries;
• uncertainty regarding our future operating results;
• weather, including its impact on oil and natural gas demand and weather-related delays on
operations;
• technology; and
• 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 levels and volatility, inflation, the cost of oil field equipment and
services, lack of availability of drilling, completion 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’’). Jones Energy, Inc. is a holding
company whose sole material asset is an equity interest in JEH.
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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 an investment in 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.
Jones Energy, Inc.’s certificate of incorporation authorizes two classes of common stock, Class A
common stock and Class B common stock. 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. Jones Energy, Inc.’s
Class A common stock has been listed on the New York Stock Exchange (‘‘NYSE’’) under the symbol
‘‘JONE’’ 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 and our horizontal
drilling expertise to develop our inventory and execute several strategic acquisitions. We have
accumulated extensive knowledge and experience in developing our Anadarko and Arkoma basin
assets, having concentrated our operations in the Anadarko basin for over 25 years and applied our
knowledge to the Arkoma basin since 2011. We have drilled over 775 total wells, including over 590
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:
• the Anadarko Basin—targeting primarily the liquids-rich Cleveland, with additional opportunities
in other prospective formations, including the Tonkawa, Marmaton and Granite Wash; and
• the Arkoma Basin—targeting the Woodford shale formation.
We seek to 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 our targeted formations.
The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil
and natural gas basins in the United States, characterized by multiple producing horizons and extensive
well control collected over 100 years of development. We leverage our extensive geologic experience in
the basins and seek to identify the most profitable exploration and development opportunities to apply
our operational expertise. The formations we target are generally characterized by oil and/or
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 production to deliver
attractive economic rates of return. Our goal is to build value through a disciplined balance between
developing our current inventory of 2,765 gross identified drilling locations, identifying new
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opportunities within our existing asset base, and actively pursuing organic leasing, strategic acquisitions
and joint development agreements. In all of our joint development agreements, we control the drilling
and completion of a well, which is the phase during which we can most effectively leverage our
operational expertise and cost discipline. Following completion, we may in some cases 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, 2014, our total estimated proved reserves were 115.3 MMBoe, of which 52%
were classified as proved developed reserves. Approximately 24% of our total estimated proved
reserves as of December 31, 2014 consisted of oil, 34% consisted of NGLs, and 42% consisted of
natural gas. As of December 31, 2014, our properties included 947 gross producing wells. For the three
years ended December 31, 2014, we drilled 279 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, 2014
Estimated Net
Proved Reserves
Acreage
Year Ended
December 31, 2014
Average Daily Net
Production
MMBoe
% Oil and
NGLs
Gross
Acreage
Net
Acreage MBoe/d
% Oil and
NGLs
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . .
Woodford . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83.0
25.4
6.9
64% 162,580
17,292
43%
38,143
39%
109,260
5,227
17,015
All properties . . . . . . . . . . . . . . . . . . . .
115.3
58% 218,015
131,502
17.0
4.0
2.2
23.2
66%
33%
27%
57%
The following table presents summary well and drilling location data for each of our key
formations for the date indicated:
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Woodford(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31, 2014
Producing
Wells
Identified
Drilling
Locations(1)
Gross
Net
Gross
Net
502
148
297
947
357
59
95
511
704
777
1,284
2,765
477
85
553
1,115
(1) Our total identified drilling locations include 518 gross locations associated with proved
undeveloped reserves as of December 31, 2014. 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.
(2) Of the 777 gross (85 net) drilling locations in the Woodford formation, 351 gross (24 net)
locations are available through our agreement with Vanguard Natural Resources. As of
December 31, 2014, we have drilled five of the eight wells required to earn the acreage
available under the Vanguard agreement. Drilling the three remaining wells will allow us
to continue development and earn additional locations under the Vanguard agreement,
which is otherwise subject to expiration in the event such drilling has not begun by April
2016.
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Our 2014 capital expenditures totaled $524 million, of which $468 million was utilized to drill and
complete wells. We currently plan to invest approximately $210 million in total capital expenditures in
2015, including approximately $190 million for drilling and completion, and $20 million for workovers
and efficiency projects. 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 2015 budgeted capital expenditures with our cash flow from operations and
projected availability under our credit facilities.
Our 2015 capital budget assumes a three rig program in the Cleveland during the first quarter,
and, assuming additional drilling and completion cost reductions can be achieved, two additional rigs
being added during the second quarter, resulting in a five rig program in the Cleveland in the second
half of 2015. We have allocated our 2015 capital expenditure budget as follows:
Drilling and completion:
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties and activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 Capital
Expenditure
Budget
(in millions)
$190
20
$210
Although we reduced our year end 2014 rig count in early 2015, we believe a reasonable rig
schedule will allow us to develop all drilling locations classified as proved undeveloped reserves in the
year-end reserve report within five years.
Business Strategies
Our goal is to increase shareholder value by managing our capital expenditures and level of activity
to maximize well level returns in the current commodity environment while also evaluating and
executing opportunities for growth of reserves, production, and cash flow through potential
partnerships, acquisitions, and leasing opportunities. We seek to achieve this goal by executing the
following strategies:
Develop Our Multi-Year Inventory.
We intend to add production and reserves through the development of our existing drilling
inventory, which we believe to be repeatable and low-risk. The Company has a long history in the
Midcontinent, having drilled over 775 wells in the area since 1988. We believe our historical drilling
experience, together with the results of substantial industry activity within our operating areas, reduces
the risk and uncertainty associated with drilling horizontal wells in these areas. As of December 31,
2014, we have identified 2,765 gross drilling locations, which gives us many years of development
drilling. We expect 100% of our development capital expenditures in 2015 to be dedicated to horizontal
drilling.
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Maintain the Lowest Cost Structure in the Plays Where We Operate.
Decades of experience in the Midcontinent 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. In the Cleveland, for example, from 2005 to
2013 we reduced our well spud-to-release time, which directly affects drilling costs, from 30 days to
26 days, and in 2014 we further reduced that metric to 23 days. During that same timeframe, we have
more than doubled our lateral lengths, which directly affects production, from approximately 2,000 feet
to approximately 4,500 feet per well. We will continue to apply this expertise while also leveraging our
leading position in our focus areas to obtain the best possible pricing from service providers which we
expect will further reduce capital costs and ultimately enhance returns. Our cost structure is particularly
important in periods of low commodity prices and gives us an advantage over other operators as we
compete for acquisitions and strategic partnerships.
Opportunistically Grow Through Exploration, Acquisitions and Strategic Partnerships.
As a complement to our development program, we look to execute acquisitions, leases and
partnerships where our operating experience can be leveraged. Given the Company’s ability to decrease
costs and ramp up drilling activity, we seek opportunities that have less PDP reserves and a large
number of high-quality drilling locations. Since 2009, we have successfully executed four significant
acquisitions and several bolt-on acquisitions in our operating areas, for an aggregate purchase price of
approximately $900 million.
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. In calendar year 2014, we leased approximately 21,000 net acres.
Joint development opportunities complement our acquisition strategy by providing a capital
efficient and risk-lowering approach to acquiring drilling opportunities. These agreements give us
control over the drilling and completion phase of the well, where we can add value by applying our low
cost structure. In this regard, we have a history of developed relationships 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 300 wells in connection with these types of agreements,
over 165 of which have been drilled in connection with an active 14-year farm-out and development
agreement with ExxonMobil.
Exploit Upside Within Our Existing Assets.
We plan to continue exploiting our proved reserves to maximize production through optimized
drilling and completion techniques. Furthermore, the stacked reservoirs within our asset base provide
exposure to additional upside potential in several emerging resource plays. We have begun assessing the
potential of both the Tonkawa and Marmaton formations in the Anadarko Basin. We expect to engage
in additional development activity within these plays as commodity prices improve. Based upon our
recent assessment, we believe that we have approximately 890 potential drilling locations in the
Tonkawa and Marmaton formations that provide us with additional resource potential. We began
testing the potential of the Tonkawa formation by drilling six wells on our acreage in 2014 and are
monitoring the production of those wells at this time. 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, and the Upper, Middle and Lower Morrow
formations. In addition, we continue to apply our proven geoscience expertise in the search for new
exploration opportunities in the greater Midcontinent region.
6
Maintain Operational Control.
We operated substantially all of the wells that we drilled and completed during 2014, allowing us
to effectively manage the timing and levels of our development spending, overall well costs and
operating expenses. In addition, we expect to operate the drilling and completion phase on
approximately 67% of our 2,765 gross identified drilling locations. With over 80% 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.
Focus on Well-Level Returns.
Our management and technical teams are focused on maximizing well-level returns, which we
believe drives shareholder value. In addition to our focus on costs and optimizing drilling and
completion techniques, our team maximizes returns by allocating capital to areas with the highest rates
of return based on commodity mix. Our drilling inventory comprises oil, natural gas and NGLs, which
enables us to adjust our development approach based on prevailing commodity prices. Despite recent
declines in commodity prices, we currently intend to capitalize on the relatively more favorable oil
pricing environment as compared to natural gas and NGLs by continuing to drill acreage with
significant oil components, where 100% of our 2015 drilling capital budget is focused. 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.
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. All of our 2015 drilling capital budget is devoted to the Anadarko basin in the U.S.
Midcontinent.
Multi-Year Drilling Inventory in Existing and Emerging Resource Plays.
Our drilling inventory consists of approximately 2,765 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 low risk, and support a relatively predictable production profile.
As of December 31, 2014, we had identified 704 gross drilling locations in the Cleveland play and 777
gross drilling locations in the Arkoma Woodford shale 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 and more recently increased through our
2014 leasing efforts. 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
2014, we drilled 134 gross wells, as compared to 97 gross wells drilled in 2013, representing a 38%
7
increase. Furthermore, we have identified additional locations in several emerging resource plays that
we intend to explore and develop in the coming years, including 324 gross locations in the Tonkawa
formation and 566 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 ten years. Having
drilled over 590 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 services providers, 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
have historically hedged a significant amount of our production from oil, gas and NGLs. For the three
years ended December 31, 2014, approximately 70% of our total production was protected by
commodity hedges. Our hedge position is reviewed monthly to evaluate the impact of new wells coming
online and changes to our development program. We intend to continue to actively hedge our future
production in order to reduce the impact of commodity price volatility on our cash flows and secure
our rates of return for up to five years. As of December 31, 2014, the market value of our existing
hedges with the lenders under our senior secured credit facility was approximately $208.5 million.
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 entire 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 company 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 controlled approximately 28% of our combined voting power and economic
interest as of December 31, 2014. We believe the equity interests of our officers and directors align
their interests and provide substantial incentive to grow the value of our business.
8
Recent Developments
Public Offering of Class A Common Stock
On February 17, 2015, we completed the issuance and sale of 7,500,000 shares of Class A common
stock to the public at a price of $10.25 per share under our registration statement on Form S-3 (the
‘‘Public Equity Offering’’). The shares of Class A common stock were issued pursuant to an
underwriting agreement, dated February 11, 2015, in which we granted the underwriters a 30-day
option to purchase up to an additional 1,125,000 shares of Class A common stock.
Private Placement of Class A Common Stock
On February 23, 2015, we completed the sale of an aggregate of $50.0 million of Class A common
stock to certain affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a direct placement
of registered shares under our registration statement on Form S-3 (the ‘‘Private Equity Offering’’).
Under the terms of the Private Equity Offering, we sold 4,761,905 shares of Class A common stock at a
purchase price of $10.50 per share.
Private Placement of Senior Unsecured Notes
On February 23, 2015, JEH and Jones Energy Finance Corp., a wholly-owned subsidiary of JEH
formed for the sole purpose of co-issuing certain of JEH’s debt, completed the sale of $250.0 million in
aggregate principal amount of 9.25% senior unsecured notes due 2023 (the ‘‘2023 Notes’’) to certain
affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a private placement (the ‘‘Notes
Offering’’). The 2023 Notes rank equally with all of our other senior unsecured indebtedness and are
effectively subordinated in right of payment to all of our secured indebtedness (to the extent of the
collateral securing such indebtedness). The 2023 Notes are fully and unconditionally guaranteed on a
senior unsecured basis by Jones Energy, Inc. and by all of JEH’s existing subsidiaries (other than the
co-issuer and two immaterial subsidiaries) and any future subsidiaries that guarantee indebtedness
under our senior secured revolving credit facility or other debt securities.
We used the net proceeds from the Public Equity Offering, the Private Equity Offering and the
Notes Offering for working capital and to repay outstanding borrowings under our senior secured
revolving credit facility.
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. Specifically, our properties and wells are located in fields that generally have been
developed over a long period of time, typically decades. Given the long productive history of these
fields, there is substantial midstream and service infrastructure in place, including natural gas and NGL
pipelines and natural gas processing plants. Observing the performance of these fields over many years
allows for greater understanding of production and reservoir characteristics, making future performance
more predictable. 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.’’
9
Anadarko Basin
Approximately 75% of our estimated proved reserves as of December 31, 2014 and approximately
77% of our average daily net production for the year ended December 31, 2014 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.
The basin has an especially well developed interval of productive Pennsylvanian age sedimentary
rocks, up to 15,000 feet thick. 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 116 gross (97 net) wells
as operator in the Anadarko basin in 2014. Our operations in the Anadarko basin are primarily focused
on the Cleveland formation where we have 502 producing wells. We also have acreage in the Tonkawa,
Marmaton, Granite Wash, Atoka shale and Cherokee shale formations located in the eastern portion of
the Texas Panhandle and western Oklahoma.
Producing Formations. Our production in the Anadarko basin is currently derived primarily from
the following formations, where we have 542 gross (382 net) producing wells and where we have
identified 1,988 gross (1,030 net) drilling locations as of December 31, 2014, of which 420 have proved
undeveloped reserves attributed to them as of December 31, 2014. See ‘‘Drilling Locations’’ for more
information regarding the processes and criteria through which these drilling locations were identified.
• Cleveland Formation. Our Cleveland acreage is primarily located in Ochiltree, Lipscomb,
Hutchinson, 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, 2014, we operated 379 gross (304 net) producing wells with an average
working interest of 80%. Our Cleveland properties contained 83.0 MMBoe of estimated net
proved reserves as of December 31, 2014, 64% of which are oil and NGLs, and generated an
average daily net production of 17.0 MBoe/d for the year ended December 31, 2014. We have
identified 704 gross (477 net) drilling locations in the Cleveland formation as of December 31,
2014. Of these 704 locations, 364 locations (52%) are attributable to proved undeveloped
reserves as of December 31, 2014. We are currently running three rigs in the Cleveland
formation and plan to spend 100% of the Company’s development budget, or approximately
$190 million, drilling and completing wells there in 2015.
• Tonkawa Formation. As of December 31, 2014, we have identified 324 gross (190 net) drilling
locations in the Tonkawa formation primarily in Lipscomb and Hemphill Counties in Texas. In
addition, the Tonkawa formation is present in the area of other properties we own located
primarily 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 shallow marine sandstone, ranging in thickness from 20 feet to
40 feet.
We drilled our first horizontal Tonkawa well in May 2010 and drilled two additional horizontal
wells in the formation under a farm-out with Samson that is not part of our current leasehold.
During 2014, we drilled six additional test wells in different areas of the Company’s leasehold
acreage in the Tonkawa formation. We have not allocated any capital expenditures to the
Tonkawa formation in our 2015 drilling budget.
• Marmaton Formation. As of December 31, 2014, we have identified 566 gross (334 net) drilling
locations in the Marmaton formation. Our properties in the Marmaton formation are all
undeveloped and span three sub- formations: properties located primarily in Ellis County,
10
Oklahoma characterized by fluvio-deltaic sands, properties located primarily in Northeast
Ochiltree and Northwest Lipscomb Counties, Texas, characterized by shallow marine sands, and
properties located primarily 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 2015
drilling budget.
• Granite Wash Formation. Our Granite Wash acreage is primarily 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 stacked, low permeability, variable lithology alluvial fan deltaic
deposits.
As of December 31, 2014, we operated 28 gross (20 net) producing wells in this formation with
an average working interest of 71%. Our Granite Wash properties contained 3.5 MMBoe of
estimated net proved reserves as of December 31, 2014, approximately 41% of which are oil and
NGLs. We have not allocated any capital expenditures to the Granite Wash formation in our
2015 drilling budget. We have 394 gross (29 net) remaining drilling locations in the Granite
Wash formation as of December 31, 2014.
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, and Upper and Lower Morrow formations. The Atoka and Cherokee
formations, in particular, have attractive geologic properties, and we may elect to pursue their
development in the future.
Arkoma Basin
Approximately 22% of our estimated proved reserves as of December 31, 2014, and approximately
18% of our average daily net production for the year ended December 2014, 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, oil and NGLs from multiple
horizons, which range in depth from 500 to 21,000 feet.
As of December 31, 2014, we operated approximately 55% 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.
• Woodford Shale Formation. Our properties in the Woodford shale formation are located primarily
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, 2014, we operated 93 gross (50 net) producing wells in the formation with
an average working interest of 54%. Our Woodford shale formation properties contained
25.4 MMBoe of estimated net proved reserves as of December 31, 2014, 43% of which are oil
and NGLs, and generated an average daily net production of 4.0 MBoe/d for the year ended
December 31, 2014. We drilled 17 gross (11 net) additional wells in the Woodford shale
formation in 2014. We have identified 777 gross (85 net) drilling locations in the Woodford shale
formation as of December 31, 2014, of which 13% have proved undeveloped reserves attributed
to them as of December 31, 2014. Of these 777 locations, 351 gross (24 net) locations are
11
available through our agreement with Vanguard Natural Resources. As of December 31, 2014,
we have drilled five of the eight wells required to earn the acreage available under the Vanguard
agreement. Drilling the three remaining wells will allow us to continue development and earn
additional locations under the Vanguard agreement, which is otherwise subject to expiration in
the event such drilling has not begun by April 2016. We have not budgeted any 2015 capital
expenditures in the Arkoma basin.
Drilling Locations
We have identified a total of 2,765 gross (1,115 net) drilling locations, all of which are horizontal
drilling locations. Of these 2,765 locations, 1,937 locations are attributable to acreage that is currently
held by production and approximately 518 (19%) are attributable to proved undeveloped reserves as of
December 31, 2014. In order to identify drilling locations, we apply geologic screening criteria based on
the presence of a minimum threshold of reservoir 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, completion 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 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, 2014, 2013 and 2012, which are based upon reserve reports
of Cawley, Gillespie & Associates, Inc., (‘‘Cawley Gillespie’’), our independent reserve engineers.
12
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.
As of December 31,
2014
2013
2012
Reserve Data:
Estimated proved reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
27,683
292,277
38,870
16,688
236,648
32,915
12,540
228,080
34,746
Total estimated proved reserves (MBoe)(1) . . . . .
115,266
89,045
85,300
Estimated proved developed reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
10,773
160,877
22,555
7,129
139,623
19,101
4,262
110,956
16,320
Total estimated proved developed reserves
(MBoe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
60,141
49,501
39,075
Estimated proved undeveloped reserves:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . .
16,910
131,400
16,315
9,559
97,025
13,814
8,278
117,124
18,426
Total estimated proved undeveloped reserves
(MBoe)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
PV-10 (in millions)(2) . . . . . . . . . . . . . . . . . . . . . .
Standardized measure (in millions)(3) . . . . . . . . . .
$
55,125
1,502
1,388
$
39,544
1,017
941
$
46,225
782
782
(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
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 initial public offering of Jones Energy, Inc. (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 beginning with December 31, 2013.
13
The following table sets forth the benchmark prices used to determine our estimated proved
reserves for the periods indicated.
As of December 31,
2014
2013
2012
Oil, Natural Gas and NGLs Benchmark Prices:
Oil (per Bbl)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (per MMBtu)(2) . . . . . . . . . . . . . . . . . . . .
NGLs (per Bbl)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . .
$94.99
4.35
33.17
$96.78
3.67
28.33
$94.71
2.76
31.27
(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, 2014, 2013 and 2012, the average realized
prices for oil were $91.06, $91.74 and $90.74 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, 2014,
2013 and 2012, the average realized prices for natural gas were $4.16, $3.13 and $2.24 per
MMBtu, respectively.
(3) Prices for NGLs in the table above reflect the average realized prices for the prior
12 months assuming ethane is recovered from the natural gas stream. 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.
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
14
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, 2014, 2013 and 2012.
PV-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of future income taxes discounted at 10% . . .
$1,502
114
(in millions)
$1,017
76
$782
—
Standardized measure . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,388
$ 941
$782
As of December 31,
2014
2013
2012
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. The audit committee of our board of directors
conducts 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
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
15
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 well
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 21 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 24 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).
Development of Proved Undeveloped Reserves
As of December 31, 2014, none of our proved undeveloped reserves at December 31, 2014 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
16
cash flow from operations and borrowings under our credit facilities. 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 increased from 39.5 MMBoe at December 31, 2013 to
55.1 MMBoe at December 31, 2014 due to (i) the conversion of 10.1 MMBoe of proved undeveloped
reserves to proved developed reserves; (ii) additions and net positive revisions of 0.2 MMBoe, primarily
due to increased interest in existing locations and increased gas commodity pricing; (iii) additions of
15.7 MMBoe from extensions and discoveries; and (iv) additions of 9.8 MMBoe for purchases of
minerals in place. Proved undeveloped reserves increased as a percentage of total reserves from 44%
for the year ended December 31, 2013 to 48% for the year ended December 31, 2014. For the year
ended December 31, 2014, we converted 10.1 MMBoe of proved undeveloped reserves to proved
developed reserves or 26% of total proved undeveloped reserves booked at December 31, 2013. We
incurred approximately $164 million in capital to convert proved undeveloped reserves to proved
developed reserves during the year ended December 31, 2014. Our 2014 capital expenditures, excluding
acquisitions, totaled $524 million, $494 million of which was used to drill and complete wells. We
expect our 2015 capital expenditure budget to be approximately $210 million, $190 million of which we
expect to use to drill and complete wells. Costs of proved undeveloped reserve development in 2014 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 2014 year-end
proved undeveloped reserves is $940 million.
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,
2014
2013
2012
Production and Operating Data:
Net Production Volumes(1):
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total (MBoe) . . . . . . . . . . . . . . . . . . . . . . . . .
2,475
21,922
2,345
8,474
1,557
17,575
1,724
6,210
746
14,066
1,773
4,863
Average net production (Boe/d) . . . . . . . . . . . .
23,216
17,014
13,287
Average Sales Price(2):
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (per Mcf) . . . . . . . . . . . . . . . . . . . . .
NGLs (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . .
$ 88.93
3.78
32.14
$ 93.22
3.16
33.30
$ 89.71
2.17
29.07
Combined (per Boe) realized . . . . . . . . . . . . . . . .
44.65
41.56
30.63
Average Unit Costs per Boe:
Lease operating expense . . . . . . . . . . . . . . . . . . .
Production tax expense . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . .
General and administrative expense(3) . . . . . . . . .
$
5.17
2.14
21.44
3.04
$
4.47
2.07
18.38
5.14
$
4.75
1.15
16.60
3.26
(1) The Lipscomb SE field constituted approximately 23% of our estimated proved reserves
as of December 31, 2014. Our production from the Lipscomb SE field was 2,862 MBoe
and 1,751 MBoe for the years ended December 31, 2014 and 2013, respectively. The 2014
production was comprised of 1,274 MBbls of oil, 5,337 MMcf of natural gas and
17
699 MBbls of NGLs. 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.
(2) Prices do not include the effects of derivative cash settlements.
(3) General and administrative includes non-cash stock-based compensation of $4.8 million,
$13.6 million and $0.6 million for the years ended December 31, 2014, 2013 and 2012,
respectively. Excluding stock-based compensation from the above metric results in average
general and administrative cost per Boe of $2.47, $2.95 and $3.15 for the years ended
December 31, 2014, 2013 and 2012, respectively.
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,
2014
2013
2012
Gross
Net
Gross
Net Gross
Net
22
Productive . . . . . . . . . . . . . . . . . . . . . . . .
Mechanical failure . . . . . . . . . . . . . . . . . . .
1
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
61
97
1 — —
132
1
44
2
108
Exploratory Wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . . — — — — — —
1
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 — —
1
2
Total Wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . .
Mechanical failure . . . . . . . . . . . . . . . . . . .
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . .
132
1
1
134
108
97
61
1 — —
1 — —
110
97
61
44
2
2
48
22
1
1
24
For the three years ended December 31, 2014, we had no developmental wells that were deemed
dry wells and three gross (two net) exploratory wells deemed dry wells. In this same period, we
experienced a total of three gross (two net) mechanical failures that were not reservoir related. As of
December 31, 2014, there were 32 gross (27 net) development wells in the process of drilling or
completion. For the three years ended December 31, 2014, we drilled 279 gross (195 net) wells as
operator with over a 98% success rate.
From January 1, 2014 through December 31, 2014, we successfully drilled 51 gross proved
undeveloped wells and completed 44 gross proved undeveloped wells.
18
Productive Wells
The following table sets forth our total gross and net productive wells by oil or natural gas
classification as of December 31, 2014.
Operated(1) . . . . . . . . . . . . . . . . . . . . . . . .
Non-operated . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
Natural Gas
Total
Gross
Net
Gross
Net
Gross
Net
252
61
313
198
13
211
315
319
634
232
68
300
567
380
947
430
81
511
(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, 2014 for each of our producing areas.
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, 2014,
over 80% of our leasehold acreage was held by existing production.
Developed Acres
Undeveloped
Acres
Total
Gross
Net
Gross
Net
Gross
Net
Cleveland . . . . . . . . . . . .
Granite Wash . . . . . . . . . .
Woodford(1) . . . . . . . . . .
Other . . . . . . . . . . . . . . .
137,787
10,553
12,363
19,593
87,326
6,617
4,379
7,444
24,793
—
4,929
7,997
21,934
162,580
— 10,553
17,292
848
27,590
2,954
109,260
6,617
5,227
10,398
All properties(2) . . . . . .
180,296
105,766
37,719
25,736
218,015
131,502
(1) Excludes unearned gross and net acreage associated with the Vanguard joint development
agreement. Earned acreage associated with the Vanguard joint development agreement is
assigned to us at the time the first well in each unit is completed.
(2) Includes undeveloped acreage 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,
2014 that will expire over the next three years by operating area unless production is established within
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the spacing units covering the acreage prior to the expiration dates or unless the existing leases are
renewed prior to expiration.
Expiring 2015
Expiring 2016
Expiring 2017
Gross
Net
Gross
Net
Gross
Net
Cleveland . . . . . . . . . . . . . . . . . . .
Woodford . . . . . . . . . . . . . . . . . . .
Granite Wash . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
5,760
3,146
—
2,456
5,318
499
—
509
2,590
20
—
2,448
2,438
—
—
1,149
12,136
—
—
1,575
9,897
—
—
43
All properties . . . . . . . . . . . . . . .
11,362
6,326
5,058
3,587
13,711
9,940
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 operations have commenced or production from the acreage
has been established prior to such date, in which event the lease will remain in effect until the
cessation of operations or 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, 2014 attributed to acreage
whose lease expiration date precedes the 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. Recently, the United States onshore oil and natural gas industry has begun to experience a
surplus of drilling and completion rigs, equipment, pipe and personnel, due to significantly lower
commodity prices. Although this has provided a temporary respite from the previous high demand
environment, there is no assurance that market forces will not revert to the previous situation which
resulted in 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
changes 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, as described under ‘‘—Our Operations—Our Areas of Operations.’’
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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 55% for our operated leases and 38% including
all operated and non-operated leases.
Over 80% 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. In September of 2014, the Company signed a 10-year oil
gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch
Oil Pipeline, LLC will build at its expense a new oil gathering system and connect to dedicated
Company leases in Texas. The system is expected to begin service during the second quarter of 2015
and provide connectivity to both a regional refinery market as well as the Cushing market hub. Jones
Energy has reserved capacity of up to 12,000 barrels per day on the system with the potential to
increase throughput at a future date.
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
pipeline indices less any associated fees. On virtually all 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 the major NGL component products on the market, the composite price of NGL components have
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, 2014, the largest purchasers were Valero Energy Corp., NGL
Energy Partners LP, PVR Midstream LLC, Plains Marketing LP, and Monarch Natural Gas, LLC,
which accounted for approximately 22%, 12%, 12%, 10% and 10% 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.’’
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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 material 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 complete-to-earn arrangements, whereby we are
assigned title to properties from the third-party after we complete wells. Occasionally, delivery of such
assignments 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.
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
22
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:
• require the acquisition of various permits before drilling commences;
• require the installation of pollution control equipment in connection with operations;
• restrict or prohibit our drilling and production activities during periods when such activities
might affect wildlife;
• place restrictions or regulations upon the types, quantities or concentrations of materials or
substances used in our operations;
• 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;
• limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected
areas; and
• 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.
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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.
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 have not required material capital expenditures to date. In the future, we could be required
24
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 the 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 and the U.S. Army Corps of Engineers recently proposed a rule to clarify
the term ‘‘waters of the United States.’’ The proposed rule may expand federal jurisdiction under the
Clean Water Act, if it is made final in its current form. The EPA has also announced its intention to
propose regulations 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
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 the EPA is the permitting authority and released permitting
guidance on the use of diesel fuel as an additive in hydraulic fracturing fluids. 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 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 May 19, 2014, the EPA published an advance notice of rulemaking under the Toxic Substances
Control Act, to gather information regarding the potential regulation of chemical substances and
mixtures used in oil and gas exploration and production. Also, the Bureau of Land Management, or
25
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. The Interagency Working Group on Unconventional Natural Gas and Oil was
created 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 Oklahoma, have adopted similar chemical disclosure measures. Some states,
including Texas and Oklahoma, also assert the authority to shut down injection wells that are deemed
to contribute to induced seismicity, or seismic activity that is caused by human activity. 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
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
26
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. The EPA has since made several changes to the rules 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. 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. We have already reported some of our facilities as being subject to these
rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy reporting
and other administrative requirements associated with these rules. Additionally, the EPA has expressed
its intent to regulate emissions of methane and volatile organic compounds from the oil and gas sector
as a measure to implement the Climate Action Plan. While the EPA has not yet issued a rulemaking, it
has released a series of white papers addressing methane reductions from the oil and gas sector. On
January 14, 2015, the Federal Administration announced that the EPA will propose a rule in the
summer of 2015 to set standards for methane and volatile organic compound emissions from new and
modified sources in the oil and gas sector. A final rule is expected in 2016.
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,
activities adversely affecting that species or its habitat may be considered ‘‘take’’ and may incur liability.
Similar 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 the Arkoma basin of 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 limit future development activity in the affected areas. On March 27,
2014, the U.S. Fish and Wildlife Service listed the Lesser Prairie Chicken as a threatened species under
the Endangered Species Act. The designated habitat for the Lesser Prairie Chicken encompasses
significant portions of our properties in the Anadarko basin. In a special rule under ESA Section 4(d)
released simultaneously with the decision to list the Lesser Prairie Chicken as threatened, the Fish and
Wildlife Service will exempt from ‘‘take’’ certain oil and gas and other activities conducted by a
27
participant that result in an ‘‘incidental take’’ of the Lesser Prairie Chicken as long as the participant is
enrolled in, and operating in compliance with, a range-wide conservation plan endorsed by the Fish and
Wildlife Service. The range-wide conservation plan also includes a Candidate Conservation Agreement
with Assurances (CCAA) component that provides ‘‘take’’ coverage for properties enrolled into the
CCAA before the listing is effective. To mitigate the risk of liability from ‘‘incidental takes’’ of the
Lesser Prairie Chicken, we enrolled affected leasehold interests in the CCAA. However, environmental
groups have challenged the listing decision and special 4(d) rule in a suit filed in federal district court
in the District of Columbia on June 17, 2014. These groups are attempting to compel a more restrictive
listing of the Lesser Prairie Chicken as endangered, rather than threatened, and are seeking to
invalidate the special 4(d) rule. While these same environmental groups also filed a notice of intent to
sue concerning the CCAA on April 10, 2014, the suit filed in federal court did not include a challenge
to the CCAA. The environmental groups’ suit could be consolidated with other suits challenging the
scientific basis for the listing filed by affected states and the oil and gas industry in Texas and
Oklahoma. We continue to evaluate the impact of these rules and legal challenges on our operations.
As with any other species in areas that we operate, the listing of the Lesser Prairie Chicken under the
Endangered Species Act could force us to incur additional costs and delay or otherwise limit or
terminate 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 production activities, as well as any
exploration and development plans that may be proposed in the future, 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 is regulating 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 and are
otherwise subject to CAA permitting requirements based on emissions of non-GHG regulated air
pollutants. 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.
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. The rule requires
reporting of GHG emissions by regulated entities to the EPA on an annual basis. Reporting was first
required in 2012 for emissions occurring in 2011. We are currently required to monitor and report
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GHG emissions under this rule, and operational and/or regulatory changes could increase the burden
of compliance with GHG emissions monitoring and reporting 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.
The federal administration also issued a Climate Action Plan in June 2013. Among other things,
the Climate Action Plan directs federal agencies to develop a strategy for the reduction of methane
emissions, including emissions from the oil and natural gas industry. As previously mentioned, the
federal administration announced that the EPA will propose a rule in the summer of 2015 to set
standards for methane and volatile organic compound emissions from new and modified sources in the
oil and gas sector, with a final rule expected in 2016. As a result of this continued regulatory focus and
other factors, additional GHG regulation of the oil and gas industry remains a possibility. Although it
is not possible at this time to predict how legislation or new regulations that may be adopted to address
GHG emissions would impact our business, any such future laws and regulations imposing reporting
obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to
incur costs to reduce emissions of GHGs associated with our operations.
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 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 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 of pollution control
activities for the years ended December 31, 2014 or 2013. Additionally, we are not aware of any
environmental issues or claims that will require material capital expenditures during 2015 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 on our business activities, financial condition or results of operations.
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Offices
We currently lease approximately 43,000 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 2020. We also lease field offices in Canadian, Texas and McAlester, Oklahoma.
Employees
As of December 31, 2014, we had 104 employees, including 34 technical (geosciences, engineering,
land), 22 field operations, 36 corporate (finance, accounting, planning, business development, IT,
human resources, office management) and 12 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.
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. As an example,
during the second half of 2014, the NYMEX-WTI oil price has fallen from more than $100 per Bbl to
below $50 per Bbl, the lowest price seen since 2009. These markets will likely continue to be volatile in
the future, especially given the current geopolitical conditions. The prices we receive for our production
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and the levels of our production depend on numerous factors beyond our control. These factors include
the following:
• regional and worldwide economic conditions impacting the supply and demand for oil, natural
gas and NGLs;
• the actions of the Organization of Petroleum Exporting Countries;
• the price and quantity of imports of foreign oil, natural gas and NGLs;
• political conditions regionally, domestically or in other oil and gas-producing regions;
• the level of domestic and global oil and natural gas exploration and production;
• the level of domestic and global oil and natural gas inventories;
• localized supply and demand fundamentals and transportation availability;
• weather conditions and natural disasters;
• domestic, local and foreign governmental regulations and taxes;
• speculation as to the future price of oil, natural gas and NGLs and the speculative trading of oil,
natural gas and NGLs;
• trading prices of futures contracts;
• price and availability of competitors’ supplies of oil, natural gas and NGLs;
• technological advances affecting energy consumption;
• the price and availability of alternative fuels; and
• 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 2014 production, and
we realized an average price of $32 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 at some point, 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 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.
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
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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
commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including
the following:
• delays imposed by or resulting from compliance with regulatory and contractual requirements
and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of
greenhouse gases;
• pressure or irregularities in geological formations;
• shortages of or delays in obtaining equipment and qualified personnel;
• equipment failures or accidents;
• lack of available gathering facilities or delays in construction of gathering facilities;
• lack of available capacity on interconnecting transmission pipelines;
• fires and blowouts;
• adverse weather conditions, such as hurricanes, blizzards and ice storms;
• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures,
encountering naturally occurring radioactive materials, and unauthorized discharges of brine,
well stimulation and completion fluids, toxic gases or other pollutants into the surface or
subsurface environment;
• declines in oil, natural gas and NGL prices;
• limited availability of financing at acceptable rates;
• title problems; and
• 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:
• effectively controlling the level of pressure flowing from particular wells;
• landing our wellbore in the desired drilling zone;
• staying in the desired drilling zone while drilling horizontally through the formation;
• running our casing the entire length of the wellbore; and
• 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:
• the ability to fracture stimulate the planned number of stages;
• the ability to run tools the entire length of the wellbore during completion operations; and
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• 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
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 2014 were $524 million and our budgeted capital
expenditures for 2015 are $210 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 senior secured revolving credit facility, through the
issuance of debt securities 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 senior secured
revolving credit facility and the issuance of additional debt and equity securities. Our cash flow from
operations and access to capital are subject to a number of variables, including:
• the estimated quantities of our oil, natural gas and NGL reserves;
• the amount of oil, natural gas and NGLs we produce from existing wells;
• the prices at which we sell our production;
• any gains or losses from our hedging activities;
• the costs of developing and producing our oil, natural gas and NGL reserves;
• take-away capacity;
• our ability to acquire, locate and produce new reserves;
• the ability and willingness of banks to lend to us; and
• 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 the indentures governing our senior notes due
2022 (the ‘‘2022 Notes’’) and senior notes due 2023 (the ‘‘2023 Notes’’) 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
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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 through
the capital markets 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 48% of our total estimated proved reserves were classified as proved undeveloped
as of December 31, 2014. 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
our reserves, increases in costs to drill and develop such reserves or declines in commodity prices 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.
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 NGL 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
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 limits 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,
2015, 2016, and 2017, approximately 37%, 62%, and 77%, respectively, of our estimated total oil,
natural gas and NGL production from proved reserves, based on our reserve report as of December 31,
2014, 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.
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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.
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
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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.
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 exploration, 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
36
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 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.
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 be accompanied by 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,
2014. 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
37
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.
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:
• commodity price hedging and actual prices we receive for oil, natural gas and NGLs;
• actual cost of development and production expenditures;
• the amount and timing of actual development and production; and
• 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, 2014
excluding hedging impacts would decrease approximately $201.1 million holding all costs constant. If
natural gas prices decline by $1.00 per Mcf, then our standardized measure as of December 31, 2014
excluding hedging impacts would decrease by approximately $136.2 million holding all costs constant. In
the event lower commodity prices persist, we would expect the cost of oil field equipment and services
to decline, thereby increasing the returns on our potential drilling opportunities.
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Over 99% 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 99% of our estimated proved reserves as of December 31, 2014 were located in the
Anadarko and Arkoma basins in the Texas Panhandle and Oklahoma. Approximately 71% of our 2014
production was from the Cleveland formation where properties are 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.
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, 2014 purchases by our top five customers accounted for
approximately 22%, 12%, 12%, 10% and 10%, 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 impose certain limitations on our ability to
enter into mergers or combination transactions. Our senior secured revolving credit facility also limits
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:
• the validity of our assumptions about estimated proved reserves, future production, commodity
prices, revenues, capital expenditures, operating expenses and costs;
• an inability to successfully integrate the assets we acquire;
• an inability to obtain satisfactory title to the assets we acquire;
• a decrease in our liquidity by using a significant portion of our available cash or borrowing
capacity to finance acquisitions;
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• a significant increase in our interest expense or financial leverage if we incur additional debt to
finance acquisitions;
• the assumption of unknown liabilities, losses or costs for which we obtain no or limited
indemnity or other recourse;
• the diversion of management’s attention from other business concerns;
• an inability to hire, train or retain qualified personnel to manage and operate our growing
assets; and
• 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 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 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 complete-to-earn arrangements,
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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.
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
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
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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
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.
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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:
• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic
gas or other pollution into the environment, including groundwater contamination;
• adverse weather conditions and natural disasters;
• encountering abnormally pressured formations;
• facility or equipment malfunctions;
• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
• fires, explosions and ruptures of pipelines;
• personal injuries and death; and
• terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial
losses to us as a result of:
• injury or loss of life;
• damage to and destruction of property, natural resources and equipment;
• pollution and other environmental damage and associated clean-up responsibilities;
• regulatory investigations, penalties or other sanctions;
• suspension of our operations; and
• repair and remediation costs.
We 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
43
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
arise under a wide range of federal, state and local environmental laws and regulations, including, for
example:
• the Clean Air Act, or CAA, and comparable state laws and regulations that impose obligations
related to air emissions;
• 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;
• 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;
• 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;
• the Environmental Protection Agency’s, or the 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;
• 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;
• 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;
• 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
• 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
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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
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 the 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, the EPA issued a notice of 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
45
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
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 has also released several
papers for public and peer review. The study remains ongoing.
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. 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. The Interagency Working
Group on Unconventional Natural Gas and Oil was created 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.
State and federal regulatory agencies recently have focused on a possible connection between the
operation of injection wells used for oil and gas waste waters and an observed increase in minor
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seismic activity and tremors. When caused by human activity, such events are called induced seismicity.
In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced
injection volumes or suspended operations, often voluntarily. A 2012 report published by the National
Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection
wells have been suspected to be, or have been, the likely cause of induced seismicity. However, some
state regulatory agencies have modified their regulations to account for induced seismicity. For
example, the Texas Railroad Commission rules allow the Commission to modify, suspend, or terminate
a permit based on a determination that the permitted activity is likely to be contributing to seismic
activity. The Oklahoma Corporation Commission also asserts authority to shut down injection wells that
it considers linked to induced seismicity, and has recently taken other steps to regulate injection wells
that may contribute to induced seismicity. Regulatory agencies are continuing to study possible linkage
between injection activity and induced seismicity.
Further, on April 17, 2012, the EPA released final rules to subject 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 are 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. The EPA has
since reconsidered several aspects of the rules and may continue to make changes. 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. We have reported some of our facilities as being subject to
these rules and have incurred, and will continue to incur, costs to control emissions, and to satisfy
reporting and other administrative requirements associated with these rules. We continue to evaluate
the effect these rules will have on our business. On January 14, 2015, the federal administration
announced that the EPA will propose a rule in the summer of 2015 to set standards for methane and
volatile organic compound emissions from new and modified sources in the oil and gas sector. A final
rule is expected in 2016. The Administration’s announcement also stated that other federal agencies,
including the Bureau of Land Management, the Pipeline and Hazardous Materials Safety
Administration, and the Department of Energy will impose new or more stringent regulations on the
oil and gas sector that will have the effect of further reducing methane emissions. 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.
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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; and actual impacts of
climate change like extreme weather conditions could adversely affect our operations.
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 promulgated 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. 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. We are currently
required to monitor and report GHG emissions under this rule, and operational and/or regulatory
changes could increase the burden of compliance with GHG emissions monitoring and reporting
requirements.
The Climate Action Plan also calls for reductions of methane emissions. As previously mentioned,
the federal administration has previously announced that the EPA will issue a proposed rule to require
methane reductions from oil and gas sources in the summer of 2015, with a final rule expected in 2016.
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,
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. Therefore, the cost to
48
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:
• we cannot obtain future permits from applicable regulatory agencies;
• water of lesser quality or requiring additional treatment is produced;
• our wells produce excess water;
• new laws and regulations require water to be disposed in a different manner; or
• 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,
2014, we had approximately $265 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 $625 million available under our revolving credit facility
would result in increased annual interest expense of approximately $6 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.
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:
• our joint development partners may share certain approval rights over major decisions;
• 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;
• we may incur liabilities as a result of an action taken by our joint development partners;
49
• 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
• 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, 2014, the Jones family and Metalmark Capital held approximately 75.2% 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.
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. Additionally, certain material misstatements were
identified by the Company in the fourth quarter with respect to our financial statements for the interim
periods ended March 31, 2014, June 30, 2014 and September 30, 2014 related to an error in the
calculation of depletion, depreciation and amortization included in the Company’s consolidated
financial statements as reported in the Company’s Quarterly Reports on Forms 10-Qs. See
‘‘Supplemental Quarterly Financial Information (Unaudited)’’ for restated financial information. This
material weakness resulted in a misstatement of account balances that resulted in a material
misstatement to the interim consolidated financial statements. We concluded that these control
deficiencies constituted a material weakness in our control environment. A material weakness is a
50
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.
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 requires us, among other things, to annually review and report on the
effectiveness of our internal controls over financial reporting. 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 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
requirements that apply to other public companies.
We continue to qualify as an ‘‘emerging growth company’’ under the Jumpstart Our Business
Startups Act (the ‘‘JOBS Act’’). By virtue of such, 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 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
51
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.
We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we 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 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 Units for shares of Class A common stock (or resulting from a sale of JEH Units to us 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. 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 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 or us.
52
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 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
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 our 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 periods indicated.
2014
2013
High
Low
High
Low
1st Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2nd Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .
3rd Quarter(1) . . . . . . . . . . . . . . . . . . . . . . . . .
4th Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$18.32
$20.57
$20.79
$18.82
$13.05
$14.50
$17.26
$ 9.50
—
—
$17.10
$18.14
—
—
$13.60
$13.15
(1) For the third quarter of 2013, the data represents the period from July 24, 2013, the date
on which our common stock began trading on the NYSE, through September 30, 2013.
On February 27, 2015, the last sale price of our common stock, as reported on the NYSE, was
$8.54 per share. As of February 27, 2015, there were 25,208,402 shares of Class A common stock
outstanding held by approximately five stockholders of record and 36,422,660 shares of Class B
common stock outstanding held by approximately eleven 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 the 2022 Notes prohibit us from paying dividends.
Issuer Purchases of Equity Securities
None.
Sales of Unregistered Equity Securities
None.
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.
54
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, 2014.
$140
$130
$120
$110
$100
$90
$80
$70
$60
24-J U L-13
31-A U G-13
30-S E P-13
31-O C T-13
30-N O V-13
31-D E C-13
31-J A N-14
28-F E B-14
31-M A R-14
30-A P R-14
31-M A Y-14
30-J U N-14
31-J U L-14
31-A U G-14
30-S E P-14
JONE
S&P 500
S&P O&G E&P Index
31-O C T-14
31-D E C-14
30-N O V-14
2MAR201516470331
Securities Authorized for issuance Under Equity Compensation Plans
The following table presents the securities authorized for issuance under the Jones Energy, Inc.
2013 Omnibus Incentive Plan (the ‘‘LTIP’’) as of December 31, 2014.
Plan Category
Equity compensation plan approved
by security holders(1) . . . . . . . . . .
Equity compensation plans not
approved by security holders . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Total
Number of Shares to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights ($)
Number of Shares
Remaining Available for
Future Issuance under
Equity Compensation
Plans
—
—
—
—
—
—
3,276,679(2)
—
3,276,679
(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. Our board of
directors has approved total cumulative awards of 573,321 shares of restricted Class A common
stock under the LTIP as of December 31, 2014.
55
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, 2014, 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
Operations’’ and ‘‘Item 8. Financial Statements and Supplementary Data’’ presented elsewhere in this
report.
Year Ended December 31,
(in thousands except per share data)
Operating revenues
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $378,401 $258,063 $148,967 $167,261 $ 97,523
933
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,106
1,022
2,196
847
2014
2013
2012
2011
2010
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . .
380,597
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 compensation expense) . .
43,843
18,094
3,453
181,669
27,781
12,865
1,710
114,136
— 14,415
608
770
31,902
25,763
23,097
5,583
356
80,709
18,821
533
15,875
21,548
5,333
780
68,906
31,970
413
16,679
16,296
2,206
4,208
48,008
10,727
490
11,423
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . .
273,592
203,417
144,974
145,629
93,358
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107,005
55,752
4,840
22,654
5,098
Other income (expense)
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain (loss) on commodity derivatives . . . . . . . . . . . . . . . . . . . . . .
Gain on bargain purchase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain (loss) on sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(46,726)
189,641
—
297
(30,774)
(2,566)
—
(78)
(25,292)
16,684
(21,994)
34,490
— 26,208
(859)
1,162
(12,575)
23,758
—
8,644
Other income (expense), net
. . . . . . . . . . . . . . . . . . . . . . . . .
143,212
(33,418)
(7,446)
37,845
19,827
Income (loss) before income tax . . . . . . . . . . . . . . . . . . . . . . .
250,217
22,334
(2,606)
60,499
24,925
Income tax provision
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
26,021
Total income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . .
26,074
85
(156)
(71)
—
473
473
—
173
173
—
145
145
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to non-controlling interests . . . . . . . . . . . . . . .
224,143
183,275
22,405
24,591
(3,079)
—
60,326
—
24,780
—
Net income (loss) attributable to controlling interests . . . . . . . . . . . . . . $ 40,868 $ (2,186) $ (3,079) $ 60,326 $ 24,780
Earnings per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3.26 $
3.26 $
(0.17)
(0.17)
Weighted average shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,526
12,535
12,500
12,500
Other Supplementary Data:
EBITDAX(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $301,393 $204,997 $135,741 $127,960 $ 74,771
17,599
Adjusted net income(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34,894
64,205
54,792
29,411
(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.
56
(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.
(in thousands of dollars)
Statement of Cash Flow Data
Net cash flow provided by operating
Year Ended December 31,
2014
2013
2012
2011
2010
activities . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . .
Net cash provided by financing activities . . .
$ 265,423
(463,903)
188,226
$ 148,573
(368,277)
219,798
$ 84,550
(337,636)
270,676
$ 120,217
(318,963)
186,322
$ 44,624
(90,785)
49,200
Net increase (decrease) in cash . . . . . . . . .
$ (10,254) $
94
$ 17,590
$ (12,424) $ 3,039
(in thousands of dollars)
Balance Sheet Data
Cash and cash equivalents . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . .
2014
2013
2012
2011
2010
As of December 31,
$
13,566
229,176
$
23,820
121,782
$
23,726
74,886
$
6,136
88,546
$ 18,560
49,742
Total current assets . . . . . . . . . . . . . . .
Property and equipment, net . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . .
242,742
1,642,908
107,578
145,602
1,300,672
41,705
98,612
1,010,742
41,332
94,682
743,575
42,878
68,302
495,613
21,379
Total assets . . . . . . . . . . . . . . . . . . . . .
$1,993,228
$1,487,979
$1,150,686
$881,135
$585,294
Current liabilities . . . . . . . . . . . . . . . . . .
Long-term debt
. . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . .
Total stockholders’ / members’ equity . . . .
$ 229,999
860,000
51,356
851,873
$ 179,668
658,000
26,187
624,124
$
93,421
610,000
18,865
428,400
$108,494
415,000
11,733
345,908
$ 60,938
225,000
14,907
284,449
Total liabilities and stockholders’ /
members’ equity . . . . . . . . . . . . . . . .
$1,993,228
$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
57
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.
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
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 . . . . . . . . . . .
Year Ended December 31,
2014
2013
2012
2011
2010
$ 224,143
$ 22,405
$ (3,079) $ 60,326
$ 24,780
39,848
3,453
26,074
6,878
181,669
—
770
376
4,040
758
(189,641)
4,476
(1,154)
—
(297)
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 . . . . . . . . . . . . . . . . . . . . . . . . .
$ 301,393
$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.
58
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 . . . . . . . . . . . . . .
Net unamortized capitalized loan costs . . . . .
Tax impact(1) . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2014
2013
2012
2011
2010
$ 224,143
(189,641)
$ 22,405
2,566
$ (3,079) $ 60,326
(34,490)
(16,684)
$ 24,780
(23,758)
4,476
—
4,040
758
—
3,761
16,668
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 . . . . . . . . . . . . . . . . . . . .
$ 64,205
$ 54,792
$ 29,411
$ 34,894
$ 17,599
Adjusted net income attributable to
non-controlling interests . . . . . . . . . . . . . . .
52,423
51,182
Adjusted net income attributable to controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings per share (basic) . . . . . . . . . . . . . . .
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 . . . . .
Net unamortized capitalized loan costs . . . . .
Tax impact . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted earnings per share (basic) . . . . . . . . .
Earnings per share (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 . . . . .
Net unamortized capitalized loan costs . . . . .
Tax impact . . . . . . . . . . . . . . . . . . . . . . . . .
$ 11,782
$ 3,610
$
$
3.26
(3.85)
(0.17)
0.43
$
$
0.09
—
0.08
0.02
0.08
1.26
0.94
3.26
(3.85)
0.09
—
0.08
0.02
0.08
1.26
0.94
$
$
(0.01)
0.29
0.02
—
—
(0.27)
0.29
(0.17)
0.43
(0.01)
0.29
0.02
—
—
(0.27)
$
0.29
Adjusted earnings per share (diluted) . . . . . . .
$
Effective tax rate on net income attributable to
controlling interests . . . . . . . . . . . . . . . . . . .
35.7%
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.
59
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 focused in the Anadarko and
Arkoma basins of Texas and Oklahoma. We have drilled over 775 total wells, including over 590
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, 2014, our total estimated proved reserves were 115.3 MMBoe, of which 52%
were classified as proved developed reserves. Approximately 24% of our total estimated proved
reserves as of December 31, 2014 consisted of oil, 34% consisted of NGLs, and 42% consisted of
natural gas.
Outlook
We have identified 2,765 gross drilling locations in our areas of operation, which gives us many
years of development drilling. In the second half of 2014, prices for oil, NGLs and natural gas declined
rapidly, with oil and NGL prices hitting a 6-year low and natural gas prices hitting a 3-year low. We
believe that the commodity pricing environment will remain challenging for 2015. However, we believe
that our ability to reduce drilling and completion costs, our existing drilling inventory, and our strong
hedge position will enable us to generate attractive economic rates of return and to compete for
strategic acquisitions and joint development opportunities.
Our 2014 capital expenditures totaled $524 million, of which $468 million was utilized to drill and
complete wells. We currently plan to invest approximately $210 million in total capital expenditures in
2015, including approximately $190 million for drilling and completion, and $20 million for workovers
and efficiency projects. Please see ‘‘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 2015 budgeted capital expenditures with our cash flow from operations and
projected availability under our senior secured revolving credit facility.
Our 2015 capital budget assumes a three rig program in the Cleveland during the first quarter,
and, assuming additional drilling and completion cost reductions can be achieved, two additional rigs
60
being added during the second quarter, resulting in a five rig program in the Cleveland in the second
half of 2015. We have allocated our 2015 capital expenditure budget as follows:
Drilling and completion:
Cleveland . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
All properties and activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 Capital
Expenditure
Budget
(in millions)
$190
20
$210
Although we reduced our year end 2014 rig count in early 2015, we believe a reasonable rig
schedule will allow us to develop all drilling locations classified as proved undeveloped reserves in the
year-end reserve report within five years.
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
28% of our 2014 and 2013 production, has recently hit a six-year low, 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. 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 swaps 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 protection against declines in oil and gas prices, and may 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 lenders
under the Revolver, and our hedge positions are generally 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 balance sheet. During the year ended December 31, 2014, 78% of our total production
61
for oil, natural gas and NGLs was hedged. As of December 31, 2014, approximately 50% of our total
forecasted production from proved reserves through 2016 was hedged, and the market value of our
hedge position was $209 million. We do not anticipate any substantial changes in our hedging policy.
Our open positions as of December 31, 2014 were as follows:
Year Ending December 31,
2015
2016
2017
2018
2019
Oil positions(1):
Swaps:
Hedged volume (MBbl) . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Bbl) . . . . . . . . . . . . . . . . . .
2,322
$ 84.71
1,809
$ 83.81
769
$ 84.56
581 —
$82.75 —
Natural gas positions(2):
Swaps:
Hedged volume (MMcf) . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Mcf) . . . . . . . . . . . . . . . . . .
19,543
4.47
$
16,230
4.49
$
11,660
4.35
$
8,980 —
$ 4.29 —
NGL positions(3):
Swaps:
Hedged volume (MBbl) . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/gal) . . . . . . . . . . . . . . . . . .
1,536
0.97
$
238
1.19
$
42
1.53
$
— —
— —
Natural Gas Basis positions(4):
Swaps:
Hedged volume (MMcf) . . . . . . . . . . . . . . . . . . . . . . .
Weighted average price ($/Mcf) . . . . . . . . . . . . . . . . . .
9,750
1,000
$ (0.22) $ (0.28)
—
—
— —
— —
(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 natural 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 natural 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.
62
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.
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 oil and gas properties to no more than the fair value of the particular field for which
impairment recognition is required and the cost to expense the remaining amount of the carrying value
of each field of unproved oil and gas properties based on a periodic impairment assessment requiring
significant judgment. We assess our unproved properties periodically for impairment on a
property-by-property basis based on remaining lease terms, drilling results or future plans to develop
acreage.
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 senior notes. 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.
63
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,
2014
2013
Change
2013
2012
Change
$220,090
82,947
75,364
378,401
2,196
$145,146
55,511
57,406
258,063
1,106
$ 74,944
27,436
17,958
120,338
1,090
$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
Total operating revenues . . . . . . . . . . . . . . . . .
380,597
259,169
121,428
259,169
149,814
109,355
Costs and expenses:
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . .
43,843
18,094
3,453
181,669
—
770
25,763
27,781
12,865
1,710
114,136
14,415
608
31,902
Total costs and expenses . . . . . . . . . . . . . . . . .
273,592
203,417
Operating income . . . . . . . . . . . . . . . . . . . . .
107,005
55,752
16,062
5,229
1,743
67,533
(14,415)
162
(6,139)
70,175
51,253
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
203,417
144,974
55,752
4,840
4,684
7,282
1,354
33,427
(4,406)
75
16,027
58,443
50,912
Other income (expenses):
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain (loss) on commodity derivatives
. . . . . . . . .
Gain (loss) on sales of assets . . . . . . . . . . . . . . . . .
(46,726)
189,641
297
(30,774)
(2,566)
(78)
(15,952)
192,207
375
(30,774)
(2,566)
(78)
(25,292)
16,684
1,162
(5,482)
(19,250)
(1,240)
Total other income (expense) . . . . . . . . . . . . . .
143,212
(33,418)
176,630
(33,418)
(7,446)
(25,972)
Income (loss) before income tax . . . . . . . . . . . . . . .
Income tax provision (benefit) . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to non-controlling interests . . . .
250,217
26,074
224,143
183,275
22,334
(71)
22,405
24,591
227,883
26,145
201,738
158,684
22,334
(71)
22,405
24,591
(2,606)
473
(3,079)
—
24,940
(544)
25,484
24,591
Net income (loss) attributable to controlling interests . . .
$ 40,868
$ (2,186)
$ 43,054
$ (2,186)
$ (3,079)
$
893
Net production volumes:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total (MBoe)
. . . . . . . . . . . . . . . . . . . . . . . . .
Average net (Boe/d) . . . . . . . . . . . . . . . . . . . . .
Average sales price, unhedged:
Oil (per Bbl), unhedged . . . . . . . . . . . . . . . . . . . .
Natural gas (per Mcf), unhedged . . . . . . . . . . . . . .
NGLs (per Bbl), unhedged . . . . . . . . . . . . . . . . . .
Combined (per Boe) realized, unhedged . . . . . . . .
Average sales price, hedged:
Oil (per Bbl), hedged . . . . . . . . . . . . . . . . . . . . . .
Natural gas (per Mcf), hedged . . . . . . . . . . . . . . . .
NGLs (per Bbl), hedged . . . . . . . . . . . . . . . . . . . .
Combined (per Boe) realized, hedged . . . . . . . . . .
Average costs (per BOE):
Lease operating . . . . . . . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . .
1,557
17,575
1,724
6,210
17,014
93.22
3.16
33.30
41.56
87.86
3.93
33.26
42.40
4.47
2.07
18.38
5.14
$
$
$
918
4,347
621
2,264
6,202
(4.29)
0.62
(1.16)
3.09
0.30
0.09
(0.66)
2.78
0.70
0.07
3.06
(2.10)
1,557
17,575
1,724
6,210
17,014
93.22
3.16
33.30
41.56
87.86
3.93
33.26
42.40
4.47
2.07
18.38
5.14
$
$
$
$
$
$
746
14,066
1,773
4,863
13,287
89.71
2.17
29.07
30.63
87.30
3.76
34.22
36.76
4.75
1.15
16.60
3.26
$
$
$
811
3,509
(49)
1,347
3,727
3.51
0.99
4.23
10.93
0.56
0.17
(0.96)
5.64
(0.28)
0.92
1.78
1.88
$
$
$
2,475
21,922
2,345
8,474
23,216
88.93
3.78
32.14
44.65
88.16
4.02
32.60
45.18
5.17
2.14
21.44
3.04
$
$
$
64
Results of Operations—Year ended December 31, 2014 as compared to year ended December 31, 2013
Operating revenues
Oil and gas sales. Oil and gas sales increased by $120.3 million (46.6%) to $378.4 million for the
year ended December 31, 2014, as compared to $258.1 million for the year ended December 31, 2013.
The majority of the increase (67.8%) was due to higher crude oil production volumes with the
remainder of the increase being primarily attributable to higher natural gas and natural gas liquid
production volumes. Average daily production increased 36.5% to 23,216 Boe per day for the year
ended December 31, 2014 as compared to 17,014 Boe per day for the year ended December 31, 2013.
Crude oil production increased 59.0% from 1,557 MBbls for the year ended December 31, 2013 to
2,475 MBbls for the year ended December 31, 2014, primarily resulting from the wells acquired from
Sabine at the end of 2013, combined with an increase in the number of wells drilled in 2014. Natural
gas production increased 24.7% from 17,575 MMcf for the year ended December 31, 2013 to
21,922 MMcf for the year ended December 31, 2014, due to new wells added through drilling and the
acquisition of the Sabine wells. The average realized oil price, excluding the effects of commodity
derivative instruments, decreased from $93.22 per Bbl to $88.93 per Bbl, or 4.6%, year over year. The
average realized natural gas price, excluding the effects of commodity derivative instruments, increased
from $3.16 per Mcf to $3.78 per Mcf, or 19.6%, year over year. The average realized natural gas liquids
price, excluding the effects of commodity derivative instruments, decreased from $33.30 per Bbl to
$32.14 per Bbl, or 3.5%, year over year.
Costs and expenses
Lease operating. Lease operating expense increased by $16.0 million (57.6%) to $43.8 million for
the year ended December 31, 2014, as compared to $27.8 million for the year ended December 31,
2013. The increase occurred primarily in correlation with the 36.5% increase in production volumes. On
a per unit basis, lease operating expense increased by $0.70 per Boe or 15.7%, from $4.47 to $5.17 per
Boe, for the year ended December 31, 2014 as compared to the year ended December 31, 2013. 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 new wells drilled and acquired from Sabine.
Production taxes. Production taxes increased by $5.2 million (40.3%) to $18.1 million for the year
ended December 31, 2014, as compared to $12.9 million for the year ended December 31, 2013.
Overall production taxes increased in conjunction with the 46.6% increase in revenue. The average
effective rate decreased from 5.0% for the year ended December 31, 2013 to 4.8% for the year ended
December 31, 2014, primarily due to refunds of tax rebates recorded in 2014.
Exploration. Exploration expense increased from $1.7 million for the year ended December 31,
2013 to $3.5 million for the year ended December 31, 2014. The increase was related to dry hole costs
in 2014 as the Company drilled an unsuccessful exploratory well.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by
$67.6 million (59.2%) to $181.7 million for the year ended December 31, 2014, as compared to
$114.1 million for the year ended December 31, 2013. The increase was primarily the result of
continued drilling activity and the acquisition of the Sabine wells at the end of 2013. On a per unit
basis, depletion expense increased $3.06 per Boe or 16.6% to $21.44 per Boe for the year ended
December 31, 2014 as compared to $18.38 per Boe for the year ended December 31, 2013. The per
unit increase resulted from the higher cost to drill wells in 2014 compared to historical wells.
Impairment of oil and gas properties. We had no impairment charges on oil and gas properties for
the year ended December 31, 2014 as compared to impairment charges of $14.4 million for the year
ended December 31, 2013. 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
65
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. None of the 2013 charges were in the Cleveland formation.
General and administrative. General and administrative expenses decreased by $6.1 million
(19.1%) to $25.8 million for the year ended December 31, 2014, as compared to $31.9 million for the
year ended December 31, 2013. A decrease of $6.8 million related to stock compensation expense (of
which $9.6 million related to the immediate vesting of certain shares on the IPO date in 2013, offset by
$2.0 million of expense related to new incentive awards in 2014) and $2.4 million related to a one-time
non-cash distribution in 2013 to management related to the Monarch incentive plan. Excluding these
non-cash items, general and administrative expenses increased $2.7 million (14.7%) to $21.0 million for
the year ended December 31, 2014, as compared to $18.3 million for the year ended December 31,
2013. The increase in cash general and administrative expense is attributable to an increase in
personnel costs and office expense due to an increase in headcount to support our increased drilling
activity. On a per unit basis, cash general and administrative expenses decreased from $2.95 per Boe
for the year ended December 31, 2013 to $2.47 per Boe for the year ended December 31, 2014. The
increase in activity resulting from drilling and the acquisition of the Sabine properties significantly
increased production (36.5% 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 $15.9 million (51.6%) to
$46.7 million for the year ended December 31, 2014, as compared to $30.8 million for the year ended
December 31, 2013. Of the total expense, interest paid under our bank debt totaled $12.0 million and
$26.3 million for the years ended December 31, 2014 and 2013, respectively. In July 2013, a majority of
bank borrowing was paid down with the proceeds from the initial public offering. At the end of 2013,
we increased our debt to fund the Sabine acquisition. On April 1, 2014 we issued $500 million senior
notes at an interest rate of 6.75%. Proceeds from the notes were used to pay down the bank
borrowings. Interest incurred on the senior notes amounted to $25.3 million during 2014. Our average
debt outstanding for the year ended December 31, 2014 was $748.6 million as compared to
$544.9 million for the year ended December 31, 2013, and the weighted average interest rate incurred
on the outstanding borrowings was 4.98% and 4.82%, respectively.
Gain (loss) on commodity derivatives. We had a net gain on commodity derivatives of
$189.6 million for the year ended December 31, 2014 as compared to a net loss of $2.6 million for the
year ended December 31, 2013. The increase is attributable to decreases in crude oil prices year over
year (crude oil prices averaged $93.00 during 2014 as compared to $97.97 during 2013), combined with
decreases in future crude oil prices from 2013 to 2014. The 12-month forward prices at December 31,
2014 for crude oil averaged $59.11 per Bbl as compared to $91.70 per Bbl at December 31, 2013.
Natural gas prices, however, increased, averaging $4.42 in 2014 as compared to $3.65 in 2013, partially
offsetting the contraction in oil prices.
Gain (loss) on sales of assets. The gain (loss) on sales of assets was a gain of $0.3 million for the
year ended December 31, 2014, compared to a loss of $0.1 million for the year ended December 31,
2013.
Income taxes. The provision for income taxes reflects our reorganization and recapitalization
which occurred in connection with the Company’s initial public offering. Following the IPO in July
2013, the Company is subject to federal and state income and franchise taxes, while only the Texas
franchise tax applied to JEH prior to the IPO. Income tax expense was an expense of $26.1 million for
the year ended December 31, 2014 compared to a benefit of $0.1 million for the year ended
December 31, 2013. The non-controlling interest was allocated its proportionate share of the Texas
franchise tax expense incurred during 2014 and 2013.
66
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,
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
67
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
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 2012 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, 2012.
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
68
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 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. 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.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been private and public sales of our debt and
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 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 Revolver (as defined below),
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, 2014 reflects a positive
working capital balance largely due to the $112.7 million increase in current commodity derivative
assets. We have historically and in the future expect to maintain a negative working capital balance, and
we use our Revolver to help manage our working capital. Our borrowing base at December 31, 2014
was $625 million of which $360 million was utilized and $265 million was available.
Our 2015 capital budget will be primarily focused on the development of existing core areas in the
Cleveland play through exploitation and development. The amount of capital we expend may fluctuate
materially based on the market conditions for commodity prices and costs of drilling and completing
wells, the economic returns being realized and the success of our drilling results as the year progresses.
We expect to fund our entire 2015 capital budget with cash flows from operations and borrowings
under our Revolver. If necessary, we may also access capital through proceeds from potential asset
dispositions and the future issuance of debt and/or equity securities.
On February 17, 2015, we completed the issuance and sale of 7,500,000 shares of Class A common
stock to the public at a price of $10.25 per share (the ‘‘Public Equity Offering’’). On February 23, 2015,
we completed the sale of an aggregate of $50 million of our Class A common stock and $250 million in
aggregate principal amount of our 9.25% senior unsecured notes due 2023 to certain affiliates of GSO
Capital Partners LP and Magnetar Capital LLC in a private placement (the ‘‘Private Placements’’). The
net proceeds of the Public Equity Offering and the Private Placements were primarily used to repay
outstanding borrowings under our Revolver.
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
69
capital expenditures until later periods in order to achieve the desired balance between sources and
uses of liquidity and to prioritize capital projects that we believe have the highest expected returns and
potential to generate near-term cash flow. For example, due to the steep reduction of commodity prices
experienced in the fourth quarter of 2014, we reduced our capital budget for 2015 to $210 million. We
may also increase our capital expenditures significantly to take advantage of opportunities we consider
to be attractive. We consistently monitor and adjust our projected capital expenditures in response to
success or lack of success in drilling activities, changes in prices, availability of financing, drilling and
acquisition costs, industry conditions, the availability of rigs, contractual obligations, internally
generated cash flow and other factors both within and outside our control.
The following table summarizes our cash flows for the years ended December 31, 2014, 2013 and
2012:
Year Ended December 31,
2014
2013
2012
Net cash provided by operating activities . . . . . .
Net cash used in investing activities . . . . . . . . . .
Net cash provided by financing activities . . . . . .
$ 265,423
(463,903)
188,226
(in thousands)
$ 148,573
(368,277)
219,798
$ 84,550
(337,636)
270,676
Net increase (decrease) in cash . . . . . . . . . . . . .
$ (10,254) $
94
$ 17,590
Cash Flow Provided by Operating Activities
Net cash provided by operating activities was $265.4 million for the year ended December 31, 2014
as compared to cash provided by operating activities of $148.6 million for the year ended December 31,
2013. The increase in operating cash flows was primarily due to a $120.3 million increase in oil and gas
revenues for the year ended December 31, 2014 as compared to the year ended December 31, 2013.
The increase in revenue was primarily driven by a 59.0% increase in oil production volumes as a result
of drilling and the acquisition of the Sabine wells in the fourth quarter of 2013, combined with
increases in natural gas and NGL production volumes.
Net cash provided by operating activities was $148.6 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 acquisition of the Chalker wells in the fourth quarter of 2012, combined with
increases in crude oil and natural gas volumes.
Our operating cash flows are sensitive to a number of variables, the most significant of which is
oil, NGL, and natural 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 $463.9 million for the year ended December 31, 2014 as
compared to cash used in investing activities of $368.3 million for the year ended December 31, 2013.
The increase was primarily driven by higher capital expenditures which increased $277.0 million during
the year ended December 31, 2014 as compared to the year ended December 31, 2013 due to an
increase in drilling activity. The increase in capital expenditures was partially offset by the absence of
acquisitions of property during 2014 as compared to the $178.2 million acquisition of the Sabine
properties at the end of 2013. $15.7 million was refunded in 2014 after determining the final purchase
price of the Sabine properties that were acquired in 2013. Additionally, cash flows from current period
70
settlements of our commodity derivative instruments were net payments of $3.7 million for the year
ended December 31, 2014 as compared to net receipts of $7.6 million for the year ended December 31,
2013 as a result of higher commodity prices that occurred early in the year 2014.
Net cash used in investing activities was $368.3 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 during the year ended December 31, 2013.
We expect our 2015 capital expenditures to be approximately $210.0 million, which is a 59.9%
decrease from the $523.6 million incurred for 2014. 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 $188.2 million for the year ended December 31, 2014
as compared to net cash provided by financing activities of $219.8 million for the year ended
December 31, 2013. The decrease in cash flows provided by financing activities was primarily due to net
payment on our credit facility of $311.4 million during 2014 as compared to net borrowing of
$47.3 million during 2013. The net proceeds from the issuance of our senior notes of $490.0 million
(net of expenses) in the second quarter of 2014 were used to repay borrowings under the credit
facilities of $468 million during the year ended December 31, 2014.
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.
Senior Notes due 2022
On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp. (together the
‘‘Issuers’’), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due
2022 (the ‘‘2022 Notes’’). We used the net proceeds from the issuance of the 2022 Notes to repay all
outstanding borrowings under the Term Loan (as defined below) ($160.0 million) and a portion of the
borrowings under the Revolver ($308.0 million). We subsequently terminated the Term Loan in
accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable
semi-annually on April 1 and October 1 of each year beginning October 1, 2014. As of December 31,
2014, we had $8.4 million in interest accrued related to the 2022 Notes.
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The 2022 Notes are guaranteed on a senior unsecured basis by us and by all of our existing
significant subsidiaries. The 2022 Notes will be senior in right of payment to any future subordinated
indebtedness of the Issuers.
We may redeem the 2022 Notes at any time on or after April 1, 2017 at a declining redemption
price set forth in the indenture, plus accrued and unpaid interest.
The indenture governing the 2022 Notes contains covenants that, among other things, limit our
ability to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock,
transfer or sell assets, make investments, create certain liens, enter into agreements that restrict
dividends or other payments from our restricted subsidiaries to us, consolidate, merge or transfer all of
our assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of
these covenants will be suspended if the 2022 Notes are rated investment grade by Standard & Poor’s
or Moody’s.
Senior Notes due 2023
On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the Issuers’
9.25% Senior Notes due 2023 (the ‘‘2023 Notes’’). We used the net proceeds from the issuance of the
2023 Notes to repay outstanding borrowings under the Revolver. The 2023 Notes bear interest at a rate
of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning
September 15, 2015.
The 2023 Notes are guaranteed on a senior unsecured basis by us and by all of our existing
significant subsidiaries. The 2023 Notes will be senior in right of payment to any future subordinated
indebtedness of the Issuers.
We may redeem the 2023 Notes at any time on or after March 15, 2018 at a declining redemption
price set forth in the indenture, plus accrued and unpaid interest.
The indenture governing the 2023 Notes contains covenants that, among other things, limit our
ability to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock,
transfer or sell assets, make investments, create certain liens, enter into agreements that restrict
dividends or other payments from our restricted subsidiaries to us, consolidate, merge or transfer all of
our assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of
these covenants will be suspended if the 2023 Notes are rated as investment grade by Standard &
Poor’s or Moody’s.
Credit Facilities
Senior Secured Revolving Credit Facility.
JEH has a $1 billion senior secured revolving credit
facility (the ‘‘Revolver’’) with Wells Fargo Bank, N.A. as the administrative agent, and a syndicate of
lenders. Availability under the Revolver is subject to a borrowing base, which is currently $562.5 million
following the issuance of the 2023 Notes. The Revolver matures in November 2019. As of
December 31, 2014, JEH had borrowings of $360 million outstanding under the Revolver. The net
proceeds from the February 2015 Public Equity Offering and Private Placements were used to repay
outstanding borrowings under the Revolver. JEH’s obligations under the Revolver are guaranteed by us
and JEH’s subsidiaries and are secured by substantially all of their assets (other than equity interests of
JEH held by us).
On November 6, 2014, JEH entered into a ninth amendment (the ‘‘Ninth Amendment’’) to the
Revolver. The Ninth Amendment amended the Revolver to, among other things, (1) increase the
borrowing base under the Revolver from $550 million to $625 million, and (2) extend the maturity date
of the Revolver to November 6, 2019. The foregoing description of the Ninth Amendment is not
72
complete and is qualified by reference to the complete document, which was filed as Exhibit 10.1 to
our third quarter 2014 Form 10-Q and is incorporated herein by reference.
The borrowing base under our Revolver will be redetermined at least semi-annually on or about
April 1 and October 1 of each year. JEH and the administrative agent (acting at the direction of
lenders holding at least 662⁄3% of the outstanding loans) may each request one unscheduled borrowing
base redetermination between each scheduled redetermination. In addition, the 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 may also be reduced as a result of our issuance of unsecured notes, our
termination of material hedging positions or our consummation of significant asset sales.
If the aggregate outstanding principal amount of the revolving loans under the Revolver 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 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 or from 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.
Interest on loans under our Revolver is calculated, at JEH’s option, at either (i) the LIBO Rate
for the applicable interest period plus a margin ranging from 1.50% to 2.50% based on the level of
borrowing base utilization at such time or (ii) the greatest of (x) the prime rate announced by Wells
Fargo Bank, N.A. in effect on such day, (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 1.50% based on the level of
borrowing base utilization at such time. JEH 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 Revolver contains various covenants that, among other things, limit our ability to:
• incur indebtedness;
• grant liens on our assets;
• pay dividends or distributions or redeem any of our equity interests;
• make certain investments, loans and advances;
• merge into or with or consolidate with any other person, or dispose of all or substantially all of
our property to any other person;
• engage in certain asset dispositions;
• enter into transactions with affiliates;
• grant negative pledges or agree to restrict dividends or distributions from subsidiaries;
• allow gas imbalances, take-or-pay or certain other prepayments with respect to oil and gas
properties; and
• enter into certain derivative arrangements.
The Revolver 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 and the
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activities of a passive holding company and assets and operations incidental thereto (including the
maintenance of cash and reserves for the payment of operational costs and expenses).
Jones Energy, Inc. and its consolidated subsidiaries are also required under the Revolver to
maintain the following financial ratios:
• 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
• 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 Revolver. If an event of default exists
under the Revolver, the lenders will be able to accelerate the obligations outstanding under the
Revolver and exercise other rights and remedies. Our Revolver contains customary events of default,
including the occurrence of a change of control, as defined in the Revolver.
Second Lien Term Loan Facility.
In addition, prior to the issuance of the 2022 Notes JEH had a
$160 million second lien term loan facility (the ‘‘Term Loan’’) with Wells Fargo Energy Capital, Inc., as
the administrative agent, and a syndicate of lenders. All outstanding borrowings on the Term Loan
were repaid using a portion of the proceeds obtained from issuing the 2022 Notes in the second
quarter 2014. The Company subsequently terminated the Term Loan in accordance with its terms.
Off-Balance Sheet Arrangements
At December 31, 2014, we did not have any off-balance sheet arrangements.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2014:
Payments Due by Period
Total
Less than
1 Year
1 - 3 Years
4 - 5 Years
Thereafter
(dollars in thousands)
Long-term debt obligations . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . .
Drilling rig commitments . . . . . . . . . . . . . . . .
Well services commitments . . . . . . . . . . . . . .
Commodity derivative obligations . . . . . . . . .
Operating lease obligations . . . . . . . . . . . . . .
Asset retirement obligations, discounted . . . . .
$ 860,000
285,172
16,761
4,900
28
5,536
13,610
$ — $
42,327
16,761
4,900
—
944
3,074
126,982
—
—
28
3,093
572
— $360,000
74,253
—
—
1,499
524
$500,000
41,610
—
—
—
—
9,440
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,186,007
$68,006
$130,675
$436,276
$551,050
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based on 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
74
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
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, changes in oil and natural
gas prices, cost changes, technological advances, new geological or geophysical data or other economic
75
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 or determined through
analysis, 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.
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.
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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, natural 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 balance sheet (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
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
77
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 May 2014, the Financial Accounting Standards Board (‘‘FASB’’) issued Accounting Standards
Update (‘‘ASU’’) No. 2014-09, ‘‘Revenue from Contracts with Customers,’’ which creates a new topic in
the Accounting Standards Codification (‘‘ASC’’), topic 606, ‘‘Revenue from Contracts with Customers.’’
This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the
model, an entity will be required to recognize revenue to depict the transfer of goods or services to a
customer at an amount reflecting the consideration it expects to receive in exchange for those goods or
services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty
of revenue and cash flows arising from customer contracts. The amendments are effective for fiscal
years, and interim periods within those years, beginning after December 15, 2016 and may be applied
on either a full or modified retrospective basis. Early adoption is not permitted. We do not expect the
adoption of these provisions to have a significant impact on the Company’s consolidated financial
statements. However, we will continue to assess the anticipated impact as further implementation
guidance is released from the FASB.
In August 2014, the FASB issued ASU No. 2014-15, ‘‘Presentation of Financial Statements—Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going
Concern.’’ This ASU requires management to evaluate whether there are conditions or events that raise
substantial doubt about an entity’s ability to continue as a ‘‘going concern’’ and to provide disclosures
when certain criteria are met. Substantial doubt exists when relevant conditions and events, considered
in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as
they become due within one year after the date that the financial statements are issued (or available to
be issued). The amendments are effective for fiscal years, and interim periods within those years,
beginning after December 15, 2016. Early adoption is permitted. We do not expect the adoption of
these disclosures to have a significant impact on the Company’s consolidated financial statements.
In January 2015, the FASB issued Accounting Standards Update No. 2015-01, Income Statement—
Extraordinary and Unusual Items (‘‘ASU 2015-01’’). ASU 2015-01 removes the concept of extraordinary
items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary
items, net of tax, in the income statement after income from continuing operations if an event or
transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will
no longer be allowed. ASU 2015-01 is effective for interim and annual reporting periods beginning
after December 15, 2015. The Company does not expect the adoption of this guidance to have a
material impact on its financial position, cash flows or results of operations.
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.
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
78
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,
2014 was a net asset of $208.5 million.
As of December 31, 2014, we have hedged approximately 50% of our total forecasted production
from proved reserves through December 31, 2016. 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, 2014 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 variable rate
indebtedness. The terms of the senior secured revolving credit facility 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% depending on the base rate used and the amount of the loan outstanding in relation to
the borrowing base. The base rate margins under the terminated term loan were 6.0-7.0% depending
on the base rate used and the amount of the loan outstanding. The terms of our senior notes provide
for a fixed interest rate through their respective maturity dates. During the year ended December 31,
2014, borrowings under the Revolver, the second lien term loan and the 2022 Notes bore interest at a
weighted average rate of 2.51%, 9.13% and 6.75%, respectively.
79
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.
Based on this evaluation, our principal executive officer and principal financial officer concluded
that our disclosure controls and procedures were not effective as of December 31, 2014 because of the
material weakness in internal control over financial reporting described below.
Management’s Assessment of Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our
internal control over financial reporting is a process designed under the supervision of our principal
executive officer and principal financial officer to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of our financial statements for external purposes in
accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject
to the risk that controls may become inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
As of December 31, 2014, our management assessed the effectiveness of our internal control over
financial reporting based on the criteria for effective internal control over financial reporting
established by the Committee of Sponsoring Organizations of the Treadway Commission (‘‘COSO’’) in
Internal Control—Integrated Framework (2013). Based on this assessment, management determined that,
as of December 31, 2014, a material weakness related to design and execution of our controls
continued to exist. Additionally, this material weakness could result in a misstatement of account
balances or disclosures that would result in a material misstatement to the annual or interim
consolidated financial statements that would not be prevented or detected. Because of this material
weakness, management concluded that we did not maintain effective internal control over financial
reporting as of December 31, 2014, based on the COSO criteria.
A material weakness is a deficiency, or combination of 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.
80
The material weakness resulted in an adjustment identified by the Company in the fourth quarter
with respect to the consolidated financial statements for the interim periods ended March 31, 2014,
June 30, 2014 and September 30, 2014 related to an error in the calculation of depletion, depreciation
and amortization included in the Company’s consolidated financial statements as reported in the
Company’s Quarterly Reports on Forms 10-Q. This material weakness resulted in a misstatement of
account balances that resulted in a material misstatement to the interim consolidated financial
statements.
Attestation Report of the Registered Public Accounting Firm
Pursuant to 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.
Remediation steps to address the material weakness
The material weakness in our internal control over financial reporting described above was
previously disclosed in Item 9A, Controls and Procedures of our Annual Report on Form 10-K for the
year ended December 31, 2013.
Management took steps during the year ended December 31, 2014 to address the previously
identified material weakness, 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. We have strengthened our internal control
environment through the addition of skilled accounting personnel. This team has enabled us to
expedite our month-end close process, thereby facilitating the timely preparation of financial reports.
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.
In addition to the improvements in staffing discussed above, we have designed and implemented
new accounting processes and control procedures specifically related to those areas with adjustments
identified in prior and current years. These procedures and controls, in conjunction with the staffing
improvements, made progress toward remediation of the previously noted material weakness.
Specifically, during the year-end review process, one of our annual controls over depletion,
depreciation, and amortization identified the adjustment discussed above. Going forward, the Company
intends to implement a quarterly control to address the risk that resulted in the misstatement.
Management will continue to evaluate the accounting process and related controls in order to address
the risk of future misstatements.
Shortly after the initial public offering, the Company engaged an independent accounting and
consulting firm to fulfill its internal audit needs. The principal focus of the internal audit function has
been to test the design and operating effectiveness of our controls. Based upon our testing and
evaluation of the effectiveness of our internal controls, we have concluded we have designed but not
fully implemented new processes and controls to remediate the material weakness identified as of
December 31, 2014.
Changes in Internal Control over Financial Reporting
As described above under Remediation Steps to address the material weakness, there were
changes in our internal control over financial reporting, relating to the quarter ended December 31,
2014 that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
81
Item 9B. Other Information
None.
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.
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.
82
Exhibit
No.
EXHIBIT INDEX
Description
2.1 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).
2.2 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 (incorporated
by reference to Exhibit 2.2 to the Company’s Annual Report on Form 10-K filed on
March 14, 2014).
3.1 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).
3.2 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).
4.1 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).
4.2 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).
4.3
Indenture, dated April 1, 2014, among Jones Energy Holdings, LLC, Jones Energy Finance
Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as
trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on
Form 8-K filed on April 1, 2014).
4.4 Registration Rights Agreement, dated April 1, 2014, among Jones Energy Holdings, LLC,
Jones Energy Finance Corp., the Guarantors named therein and Citigroup Global
Markets Inc., as the sole representative of the Initial Purchasers named therein
(incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K
filed on April 1, 2014).
10.1 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).
10.2 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).
10.3 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).
10.4† Jones Energy, Inc. 2014 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).
83
Exhibit
No.
Description
10.5† 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).
10.6† 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).
10.7† 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 May 27, 2014).
10.8† Form of Performance Unit Award Agreement (incorporated by reference to Exhibit 10.1
to the Company’s Current Report on Form 8-K filed on May 27, 2014).
10.9† 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).
10.10† 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).
10.11 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).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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).
10.17 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).
10.18 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).
84
Exhibit
No.
Description
10.19 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).
10.20 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
(incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on
Form 10-K filed on March 14, 2014).
10.21 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 (incorporated by reference to Exhibit 10.20 to the
Company’s Annual Report on Form 10-K filed on March 14, 2014).
10.22 Master Assignment, Agreement and Amendment No. 9 to Credit Agreement dated as of
November 6, 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 (incorporated by reference to
Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on November 10,
2014).
10.23 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
(incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on
Form 10-K filed on March 14, 2014).
10.24
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).
10.25 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).
10.26 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).
10.27 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).
10.28 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).
10.29 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).
85
Exhibit
No.
Description
10.30 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).
10.31 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).
10.32 Firm Crude Oil Gathering and Transportation Agreement, dated September 26, 2014, by
and between Monarch Oil Pipeline, LLC and Jones Energy, LLC (incorporated by
reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed on
November 10, 2014).
10.33 Gathering and Transportation Services Agreement, dated as of September 26, 2014, by and
between Monarch Oil Pipeline, LLC and Jones Energy, LLC (incorporated by reference to
Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed on November 10,
2014).
21.1* List of Subsidiaries of Jones Energy, Inc.
23.1* Consent of PricewaterhouseCoopers LLP.
23.2* Consent of Cawley Gillespie & Associates, Inc.
31.1* Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).
31.2* Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).
32.1* Section 1350 Certification of Jonny Jones (Principal Executive Officer).
32.2* Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
99.1* Summary Report of Cawley, Gillespie & Associates, Inc. for reserves as of December 31,
2014
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.
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.
*—filed herewith
†—Management contract or compensatory plan or arrangement required to be filed as an exhibit to
this 10-K pursuant to Item 15(b).
86
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 6, 2015
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 6, 2015
/s/ MIKE S. MCCONNELL
Mike S. McConnell
Director and President
March 6, 2015
/s/ ROBERT J. BROOKS
Robert J. Brooks
Executive Vice President and Chief
Financial Officer (Principal Accounting
and Financial Officer)
March 6, 2015
/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
/s/ ROBB L. VOYLES
Robb L. Voyles
Director
Director
Director
Director
Director
87
March 6, 2015
March 6, 2015
March 6, 2015
March 6, 2015
March 6, 2015
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.’’
88
‘‘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.
89
‘‘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.
90
Index to Financial Statements
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-2
Consolidated Financial Statements
F-3
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-4
Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-5
Statement of Changes in Stockholders’ / Members’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-6
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F-7
Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental Information on Oil and Gas Producing Activities . . . . . . . . . . . . . . . . . . . . . . . . . F-43
Supplemental Quarterly Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-46
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,
2014 and 2013 and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2014 in conformity with accounting principles generally accepted in the
United States of America. 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 6, 2015
F-2
Jones Energy, Inc.
Consolidated Balance Sheets
December 31, 2014 and 2013
(in thousands of dollars)
Assets
Current assets
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2014
December 31,
2013
$
13,566
149
$
23,820
45
49,861
41,761
12,512
121,519
3,374
—
242,742
1,638,860
4,048
87,055
20,352
171
51,233
42,481
16,782
8,837
2,392
12
145,602
1,297,228
3,444
25,398
15,006
1,301
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,993,228
$1,487,979
Liabilities and Stockholders’ 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
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liability under tax receivable agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 136,337
70,469
19,401
—
718
3,074
229,999
360,000
500,000
13,377
28
10,536
803
26,612
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,141,355
$
89,430
66,179
10,805
10,664
—
2,590
179,668
658,000
—
14,531
190
8,373
—
3,093
863,855
Commitments and contingencies (Note 10)
Stockholders’ equity
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares
outstanding at December 31, 2014 and 12,526,580 shares issued and outstanding at
December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Class B common stock, $0.001 par value; 36,719,499 shares issued and outstanding at
December 31, 2014 and 36,836,333 shares issued and outstanding at December 31, 2013 . .
Treasury stock, at cost; 22,602 shares at December 31, 2014 and 0 shares at December 31,
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in-capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
37
(358)
177,133
38,682
215,507
636,366
851,873
13
37
—
173,169
(2,186)
171,033
453,091
624,124
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,993,228
$1,487,979
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, 2014, 2013 and 2012
(in thousands except per share data)
Operating revenues
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2014
2013
2012
$378,401
2,196
$258,063
1,106
$148,967
847
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
380,597
259,169
149,814
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
43,843
18,094
3,453
181,669
—
770
27,781
12,865
1,710
114,136
14,415
608
23,097
5,583
356
80,709
18,821
533
expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25,763
31,902
15,875
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
273,592
203,417
144,974
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107,005
55,752
4,840
Other income (expense)
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain (loss) on commodity derivatives . . . . . . . . . . . . . . . . . . . . .
Gain (loss) on sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(46,726)
189,641
297
(30,774)
(2,566)
(78)
Other income (expense), net . . . . . . . . . . . . . . . . . . . . . . . . . . .
143,212
(33,418)
Income (loss) before income tax . . . . . . . . . . . . . . . . . . . . . . . .
250,217
22,334
(25,292)
16,684
1,162
(7,446)
(2,606)
Income tax provision (benefit)
Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . .
53
26,021
26,074
85
(156)
(71)
—
473
473
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to non-controlling interests . . . . . . . . . . . . .
224,143
183,275
22,405
24,591
(3,079)
—
Net income (loss) attributable to controlling interests . . . . . . . . . . . .
$ 40,868
$ (2,186) $ (3,079)
Earnings (Loss) per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
3.26
3.26
$
$
(0.17)
(0.17)
Weighted average shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,526
12,535
12,500
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, 2014, 2013 and 2012
(amounts in thousands)
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 .
.
.
.
.
.
.
.
.
.
.
.
.
contributions .
.
.
Reclassification of members’
.
Stock-compensation expense
.
Distribution to members .
.
.
Net income (loss)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Balance at December 31, 2013
.
Vested restricted shares .
.
.
Stock-compensation expense
.
Exchange of Class B shares for
.
.
.
Class A shares .
.
.
Treasury stock .
.
Net income .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Balance at December 31, 2014
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Common Stock
Class A
Class B
Treasury
Stock
Class A
Shares Value Shares Value Shares Value
Additional Retained
Members’
Equity
Paid-in
Capital
(Deficit)/ Non-controlling
Earnings
Interest
Total
Stockholders’ /
Members’ Equity
— $—
— —
— —
— —
— $—
— —
— —
— —
— $ — $ 345,909
85,000
—
—
—
—
570
(3,079)
—
—
$
— $ —
—
—
—
—
$
— —
13
12,500
— —
37
36,836
— —
— —
— —
— —
— —
— —
— —
— —
— —
— —
12,500
13
28 —
— —
36,836
37
— —
— —
117 —
(23) —
— —
(117) —
— —
— —
12,622
$13
36,719
$37
—
—
—
—
—
—
—
—
—
—
—
23
—
23
— 428,400
—
—
—
—
—
— 172,431
— (464,037)
10,100
—
(10,000)
—
35,537
—
—
738
—
—
— 173,169
—
—
4,040
—
—
—
—
—
—
—
(2,186)
(2,186)
—
—
—
—
—
(76)
—
—
—
—
40,868
—
—
—
—
(358)
—
—
—
—
—
—
—
464,037
—
—
(10,946)
453,091
—
—
—
—
183,275
$345,909
85,000
570
(3,079)
428,400
50
172,431
—
10,838
(10,000)
22,405
624,124
—
4,040
(76)
(358)
224,143
$(358) $
— $177,133
$38,682
$636,366
$851,873
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, 2014, 2013 and 2012
(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
Depletion, depreciation, and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-cash compensation expense (Note 9) . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Gain) loss on commodity derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(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,
2014
2013
2012
$ 224,143
$ 22,405
$
(3,079)
181,669
2,952
—
770
6,878
7,823
4,040
758
(1,154)
(189,641)
(297)
26,021
376
(832)
(565)
2,482
114,136
—
14,415
608
2,677
1,891
10,838
2,719
(469)
2,566
78
(156)
79
(56,804)
163
33,427
80,709
—
18,821
533
3,544
456
570
—
—
(16,684)
(1,162)
473
129
11,568
1,873
(13,201)
Net cash provided by operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
265,423
148,573
84,550
Cash flows from investing activities
Additions to oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of properties
Net adjustments to purchase price of properties acquired . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sales of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of other property, plant and equipment
. . . . . . . . . . . . . . . . . . . . . . . . .
Current period settlements of matured derivative contracts . . . . . . . . . . . . . . . . . . . . .
Change in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(474,619)
—
15,709
448
(1,683)
(3,654)
(104)
(197,618)
(178,173)
—
1,607
(1,634)
7,586
(45)
(125,493)
(249,007)
—
9,158
(969)
28,675
—
Net cash used in investing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(463,903)
(368,277)
(337,636)
Cash flows from financing activities
Proceeds from issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment under long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from senior notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of preferred units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of common stock, net of expenses of $15.1 million . . . . . . . . . . . . . .
Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
170,000
(468,000)
500,000
(13,416)
—
—
(358)
220,000
(172,000)
—
(683)
—
172,481
—
233,243
(38,243)
—
(9,324)
85,000
—
—
Net cash provided by financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
188,226
219,798
270,676
Net increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(10,254)
94
17,590
Cash
Beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23,820
23,726
6,136
End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 13,566
$ 23,820
$ 23,726
Supplemental disclosure of cash flow information
Cash paid for interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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)
$ 29,560
155
49,025
—
1,995
—
$ 25,414
—
41,945
—
1,516
10,000
$ 20,759
—
3,355
2,918
662
—
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Jones Energy, Inc.
Notes to the 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, the Company 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.
The Company’s certificate of incorporation authorizes two classes of common stock, Class A
common stock and Class B common stock. The Class B common stock is held by the owners of JEH
prior to the Company’s initial public offering (‘‘IPO’’) and can be exchanged (together with a
corresponding number of units representing membership interests in JEH (‘‘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 earned prior to the IPO
date is reflected in the net income 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.
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, 2014 and 2013 and the results of the operations and the cash flows for each of the three
years in the period ended December 31, 2014 include the Company and all of its subsidiaries.
F-7
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
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 value of the outstanding balance under the
Company’s Revolver (as defined in Note 6) represents fair value because the Revolver has variable
interest rates, which are reflective of the Company’s credit risk. The Company’s senior notes have a
fixed interest rate and are reported at historical value as of the initial measurement date when issued
and their fair value is discussed in Note 4. 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.
Management monitors the soundness of the financial institutions and believes the Company’s risk is not
significant.
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 consists at December 31, 2014 of derivative
positions not settled as of the balance sheet date and severance tax refunds due from state agencies
and at December 31, 2013 of the adjustments to the purchase price of the Sabine properties purchased
in December 2013 and 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
F-8
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
allowance that reflects management’s best estimate of the amounts that may not be collected. As of
December 31, 2014 and 2013, 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, including declines in commodity prices.
As of December 31, 2014, 70% of Accounts receivable—Oil and gas sales are due from 5 purchasers
and 67% of Accounts receivable—Joint interest owners are due from 5 working interest owners. As of
December 31, 2013, 79% of Accounts receivable—Oil and gas sales were due from 8 purchasers, and
77% of 2013 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, 2014, the largest
purchasers were Valero Energy Corp. (‘‘Valero’’), NGL Energy Partners LP, PVR Midstream LLC
(‘‘PVR Midstream’’), Plains Marketing LP (‘‘Plains Marketing’’), and Monarch Natural Gas LLC which
accounted for approximately 22%, 12%, 12%, 10% and 10% of consolidated oil and gas sales,
respectively. During the year ended December 31, 2013, the largest purchasers were PVR Midstream,
Unimark LLC, Mercuria Energy Group Ltd. (‘‘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.
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.
Dependence on Suppliers
The Company’s industry is cyclical, and from time to time, there can be an imbalance between the
supply of and demand for drilling rigs, equipment, services, supplies and qualified personnel. During
periods of oversupply, there can be financial pressure on suppliers. If the financial pressure leads to
work interruptions or stoppages, the Company could be materially and adversely affected. Management
believes that there are adequate alternative providers of drilling and completion services although 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.
F-9
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
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, 2014 and 2013:
(in thousands of dollars)
Mineral interests in properties
2014
2013
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wells and equipment and related facilities . . . . . . . . . . . . .
94,526
$
1,001,194
1,094,202
$
99,134
958,816
609,748
Less: Accumulated depletion and impairment
. . . . . . . . . .
2,189,922
(551,062)
1,667,698
(370,470)
Net oil and gas properties . . . . . . . . . . . . . . . . . . . . .
$1,638,860
$1,297,228
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. As of December 31, 2014 and 2013, we had no material
capitalized costs associated with exploratory wells.
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 capitalized less than $0.1 million in interest costs during 2014 for one
project. No interest costs were capitalized in 2013. Costs incurred to maintain wells and related
equipment are charged to expense as incurred.
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
$180.6 million, $113.3 million and $79.9 million for the years ended December 31, 2014, 2013 and 2012,
respectively.
F-10
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
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. No impairments of proved
properties were recorded in 2014 or 2013. The Company incurred impairment charges of $18.8 million
related to its proved oil and natural gas properties and equipment in 2012.
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 and development activity by other companies on
adjacent blocks. The Company incurred no impairment charges related to its unproved properties in
2014 or 2012. In the fourth quarter of 2013, the Company recorded an impairment charge of
$14.4 million related to its unproved Southridge properties in the Arkoma basin. 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.
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.
Other Property, Plant and Equipment
Other property, plant and equipment consisted of the following at December 31, 2014 and 2013:
(in thousands of dollars)
Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Furniture, fixtures, computers and software . . . . . . . . . . . . . . . . .
Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aircraft
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Accumulated depreciation and amortization . . . . . . . . . . . .
2014
2013
$ 1,218
3,727
988
910
219
$ 1,060
2,491
835
910
134
7,062
(3,014)
5,430
(1,986)
Net other property, plant and equipment
. . . . . . . . . . . . . . . .
$ 4,048
$ 3,444
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.
F-11
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Depreciation and amortization of other property, plant and equipment amounted to $1.1 million,
$0.8 million and $0.8 million during the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012, 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 the Company 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 (‘‘ARO’’) 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 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
F-12
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
payments. A summary of the Company’s ARO for the years ended December 31, 2014 and 2013 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
2013
$10,963
1,995
770
(109)
(55)
46
$ 9,506
1,515
608
(271)
(702)
307
ARO liability at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,610
10,963
Less: Current portion of ARO at end of year . . . . . . . . . . . . . . .
(3,074)
(2,590)
Total long-term ARO at end of year . . . . . . . . . . . . . . . . . . . . .
$10,536
$ 8,373
(1) Includes $824 related to wells acquired in 2013 (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
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.
F-13
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
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.
Liability under Tax Receivable Agreement
In connection with the IPO, the Company entered into a Tax Receivable Agreement (the ‘‘TRA’’)
which obligated the Company to make payments to certain current and former owners equal to 85% of
the applicable cash savings that the Company realizes as a result of tax attributes arising from
exchanges of JEH Units and JEI Class B shares held by those owners for Class A shares of JEI
common stock. The Company will retain the benefit of the remaining 15% of these tax savings.
As a result of exchanges made through December 31, 2014, the Company has accrued future tax
benefits of $0.9 million and has recorded this amount as a deferred tax asset on its consolidated
balance sheet. As of December 31, 2014, the Company has recorded a liability of $0.8 million
associated with its future TRA obligation. The actual amount and timing of payments made under the
TRA will depend upon a number of factors, including the amount and timing of taxable income
generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the
Company’s payments under the TRA constituting imputed interest. To the extent the Company does
not realize all of the tax benefits in future years or in the event of a change in future tax rates, this
liability may change.
As of December 31, 2014, the Company has made no payments under the TRA and does not
anticipate making a material payment under the TRA in 2015.
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 the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
Related Party Transactions
In the years ended December 31, 2013 and 2012, 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, (‘‘Monarch’’), under which Monarch has the first right to gather the
natural gas the Company produces from dedicated 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. The Company produced
approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014 and
0.8 MMBoe of natural gas and NGLs for the year ended December 31, 2013, from the 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 and Eric Niccum.
In September 2014, the Company signed a 10-year oil gathering and transportation agreement with
Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline, LLC will build, at its expense, a
new oil gathering system and connect to dedicated Company leases in Texas. At the time the Company
entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests
of Monarch Oil Pipeline, LLC and/or its parent. The system is expected to begin service during the
second quarter of 2015 and provide connectivity to both a regional refinery market as well as the
Cushing market hub. The Company has reserved capacity of up to 12,000 barrels per day on the system
with the potential to increase throughput at a future date.
Stock Compensation
JEH implemented a management incentive plan effective January 1, 2010, that provided awards of
membership interests in JEH to members of senior management (‘‘management units’’). The
management unit grants awarded prior to the initial filing of the IPO registration statement in March
2013 had a dual vesting schedule and were fully vested as of December 31, 2014. Grants awarded after
the initial IPO registration statement generally 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
F-15
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
unvested management units were converted into JEH Units and shares of Class B common stock at the
IPO date. At December 31, 2014, there were 274,385 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.
During 2014, the Company granted performance unit and restricted stock unit awards to certain
officers and employees under the Jones Energy, Inc. 2013 Omnibus Incentive Plan. The fair value of
the performance units was based on the grant date fair value (using a Monte Carlo simulation model)
and is expensed on a straight-line basis over the applicable three-year performance period. The number
of shares of Class A common stock issuable upon vesting of the performance unit awards ranges from
zero to 200% based on the Company’s total shareholder return relative to an industry peer group over
the applicable three-year performance period. The fair value of the restricted stock unit awards 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 applicable three-year vesting period.
In September 2014 and 2013, the Company granted each of the outside members of the Board of
Directors 5,486 and 6,645 shares, respectively, 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 director and
employee stock-based compensation 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 Pronouncements
In May 2014, the Financial Accounting Standards Board (‘‘FASB’’) issued Accounting Standards
Update (‘‘ASU’’) No. 2014-09, ‘‘Revenue from Contracts with Customers,’’ which creates a new topic in
the Accounting Standards Codification (‘‘ASC’’), topic 606, ‘‘Revenue from Contracts with Customers.’’
F-16
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
2. Significant Accounting Policies (Continued)
This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the
model, an entity will be required to recognize revenue to depict the transfer of goods or services to a
customer at an amount reflecting the consideration it expects to receive in exchange for those goods or
services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty
of revenue and cash flows arising from customer contracts. The amendments are effective for fiscal
years, and interim periods within those years, beginning after December 15, 2016 and may be applied
on either a full or modified retrospective basis. Early adoption is not permitted. We do not expect the
adoption of these provisions to have a significant impact on the Company’s consolidated financial
statements. However, we will continue to assess the anticipated impact as further implementation
guidance is released from the FASB.
In August 2014, the FASB issued ASU No. 2014-15, ‘‘Presentation of Financial Statements—Going
Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going
Concern.’’ This ASU requires management to evaluate whether there are conditions or events that raise
substantial doubt about an entity’s ability to continue as a ‘‘going concern’’ and to provide disclosures
when certain criteria are met. Substantial doubt exists when relevant conditions and events, considered
in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as
they become due within one year after the date that the financial statements are issued (or available to
be issued). The amendments are effective for fiscal years, and interim periods within those years,
beginning after December 15, 2016. Early adoption is permitted. We do not expect the adoption of
these disclosures to have a significant impact on the Company’s consolidated financial statements.
In January 2015, the FASB issued Accounting Standards Update No. 2015-01, Income Statement—
Extraordinary and Unusual Items (‘‘ASU 2015-01’’). ASU 2015-01 removes the concept of extraordinary
items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary
items, net of tax, in the income statement after income from continuing operations if an event or
transaction is of an unusual nature and occurs infrequently. This separate, net-of-tax presentation will
no longer be allowed. ASU 2015-01 is effective for interim and annual reporting periods beginning
after December 15, 2015. The Company does not expect the adoption of this guidance to have a
material impact on its financial position, cash flows or results of operations.
3. Acquisition of Properties
No property acquisitions that would qualify as a business combination occurred during the twelve
months ended December 31, 2014.
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 a purchase price of
$193.5 million (referred to herein as the ‘‘Sabine acquisition’’ or ‘‘Sabine’’), subject to customary closing
adjustments. The acquired assets included both producing properties and undeveloped acreage. The
purchase was financed with borrowings under the Revolver. In the second quarter of 2014, the
Company made a final determination with the sellers as to the purchase price resulting in a final
purchase price of $179.2 million. The amount of the total purchase price allocated to undeveloped oil
and gas properties was reduced by these adjustments. The adjustments were retroactively applied to our
F-17
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
3. Acquisition of Properties (Continued)
December 31, 2013 Consolidated Balance Sheet as a reduction to oil and gas properties and an
increase in receivables. The adjusted purchase price was allocated as follows:
(in thousands of dollars)
Oil and gas properties
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 32,964
147,024
(824)
Total purchase price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$179,164
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
financed with additional equity capital and borrowings under the Revolver. 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
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
F-18
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
3. Acquisition of Properties (Continued)
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
Both acquisitions qualified as a business combination under ASC 805. The valuation to determine
the fair values were 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 market at the time
of acquisition.
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.
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.
F-19
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
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.
The financial instruments carried at fair value as of December 31, 2014 and 2013, by consolidated
balance sheet caption and by valuation hierarchy, as described above are as follows:
(in thousands of dollars)
Commodity Price Hedges
December 31, 2014
Fair Value Measurements Using
(Level 1)
(Level 2)
(Level 3)
Total
Current assets . . . . . . . . . . . . . . . . . . . .
Long-term assets . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . .
Long-term liabilities . . . . . . . . . . . . . . .
$—
—
—
—
$120,604
85,162
—
—
$ 915
1,893
—
28
$121,519
87,055
—
28
(in thousands of dollars)
Commodity Price Hedges
December 31, 2013
Fair Value Measurements Using
(Level 1)
(Level 2)
(Level 3)
Total
Current assets . . . . . . . . . . . . . . . . . . . . .
Long-term assets . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . .
Long-term liabilities . . . . . . . . . . . . . . . . .
$—
—
—
—
$ 8,837
25,967
10,188
—
$ — $ 8,837
25,398
10,664
190
(569)
476
190
F-20
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
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, 2014.
Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges
Fair Value
(000’s)
Valuation Technique
Unobservable
Input
Natural gas liquid swaps . . . .
$3,045 Use a discounted cash flow Natural
Natural gas basis swaps . . . . .
approach using inputs
including forward price
statements from
counterparties
gas liquid
futures
$ (265) Use a discounted cash flow Natural
gas basis
swaps
approach using inputs
including forward price
statements from
counterparties
Range
$8.09 - $75.52
per barrel
$(0.11) - $(0.17)
per barrel
Significant increases/decreases in natural gas liquid prices 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, 2014 and 2013. 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
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 December 31, 2012, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to Level 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2013, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to Level 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(1,519)
(1,095)
(210)
(753)
2,342
(1,235)
668
476
(265)
332
2,804
Balance at December 31, 2014, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,780
Transfers from Level 3 to Level 2 represent the Company’s natural gas basis swaps for which
observable forward curve pricing information has become readily available. Purchases represent natural
gas liquid swaps that the Company entered into that do not have observable forward curve pricing
information. There were no transfers into Level 3 for the years ended December 31, 2014 and 2013.
F-21
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The following table provides the fair value of financial instruments that are not recorded at fair
value in the consolidated financial statements:
(in thousands of dollars)
Debt:
Revolver . . . . . . . . . . . . . . . . . . . . . . .
Term loan . . . . . . . . . . . . . . . . . . . . . .
2022 Notes . . . . . . . . . . . . . . . . . . . . .
December 31, 2014
December 31, 2013
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
$360,000
—
500,000
$360,000
$498,000
— 160,000
—
$498,000
160,000
—
384,375
The Revolver is 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 approximates fair value, as it is subject to short-term floating interest rates that approximate
the rates available to the Company for those periods.
The fair value of the 2022 Notes (as defined in Note 6) is based on pricing that is readily available
in the public market. Accordingly, the 2022 Notes are classified as Level 2 in the valuation hierarchy as
the pricing is based on quoted market prices for the debt securities.
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 impairment charges on the Company’s proved properties were recorded during the
years ended December 31, 2014 and 2013. During 2012, 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 during the year ended
December 31, 2012.
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 2014 or
2012.
F-22
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
4. Fair Value Measurement (Continued)
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 that could affect its future operations as
of December 31, 2014 and 2013, as follows:
Hedging Positions
Oil swaps . . . . . . . . . . . Exercise price
Barrels per month
Natural gas swaps . . . . . Exercise price
Basis swaps . . . . . . . . . . Contract differential
mmbtu per month
mmbtu per month
Natural gas liquids swaps Exercise price
Barrels per month
Oil swaps . . . . . . . . . . . . . Exercise price
Barrels per month
Natural gas swaps . . . . . . . Exercise price
mmbtu per month
Basis swaps . . . . . . . . . . . Contract differential
mmbtu per month
Natural gas liquids swaps . Exercise price
Barrels per month
December 31, 2014
Low
High
75.05
45,000
3.37
710,000
$
$
100.95
184,054
6.45
1,772,584
$
$
Weighted
Average
84.20
Final
Expiration
113,852 December 2018
4.40
1,175,275 December 2018
(0.39) $
(0.11) $
(0.21)
$
$
$
320,000
8.09
$
2,000
$
980,000
95.24
143,000
716,667 March 2016
$
42.46
50,444 December 2017
December 31, 2013
Low
High
Weighted
Average
Final
Expiration
$
81.70
29,000
$
3.88
510,000
$
320,000
6.72
$
2,000
$
$
102.84
161,613
6.90
1,290,000
$
$
89.03
96,149 December 2017
4.26
830,275 December 2017
(0.43) $
(0.11) $
(0.34)
$
690,000
95.24
118,000
467,037 March 2016
$
32.98
46,646 December 2017
The Company recognized a net gain on derivative instruments of $189.6 million for the year ended
December 31, 2014, a net loss of $2.6 million for the year ended December 31, 2013, and a net gain of
$16.7 million for the year ended December 31, 2012.
Offsetting Assets and Liabilities
As of December 31, 2014, the counterparties to our commodity derivative contracts consisted of
seven financial institutions. Substantially, all of our counterparties or their affiliates are also lenders
under the Revolver. We are not generally required to post additional collateral under our derivative
agreements.
F-23
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
5. Derivative Instruments and Hedging Activities (Continued)
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.
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, 2014 and December 31, 2013:
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
(in thousands of dollars)
December 31, 2014
Commodity derivative contracts
Assets . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . .
$208,646
(100)
$
(72)
72
$208,574
(28)
$ —
—
$208,574
(28)
December 31, 2013
Commodity derivative contracts
Assets . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . .
$ 38,071
(14,347)
$(6,035)
6,035
$ 32,036
(8,312)
$ 2,199
(2,542)
$ 34,235
(10,854)
6. Long-Term Debt
Senior Notes
On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp. (together the
‘‘Issuers’’), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due
2022 (the ‘‘2022 Notes’’). The Company used the net proceeds from the issuance of the 2022 Notes to
repay all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding
borrowings under the Revolver ($308.0 million) and for working capital and general corporate
purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The
2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1
of each year beginning October 1, 2014. As of December 31, 2014, the Company had $8.4 million in
interest accrued related to the 2022 Notes. Total interest expense related to the 2022 Notes amounted
to $25.3 million for the year ended December 31, 2014.
The 2022 Notes are guaranteed on a senior unsecured basis by the Company and by all of its
significant subsidiaries. The 2022 Notes will be senior in right of payment to any future subordinated
indebtedness of the Issuers.
The Company may redeem the 2022 Notes at any time on or after April 1, 2017 at a declining
redemption price set forth in the indenture, plus accrued and unpaid interest.
The indenture governing the 2022 Notes contains covenants that, among other things, limit the
ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends
on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements
that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company,
F-24
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
6. Long-Term Debt (Continued)
consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or
create unrestricted subsidiaries. However, many of these covenants will be suspended if the Notes are
rated investment grade by Standard & Poor’s or Moody’s.
Other 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’’), each of which have been amended periodically. On April 1, 2014, the Term
Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On
November 6, 2014, the Company amended the Revolver to, among other things, increase the borrowing
base under the Revolver from $550.0 million to $625.0 million until the next redetermination thereof,
and extend the maturity date of the Revolver to November 6, 2019. The Company’s oil and gas
properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on
the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the
issuance of the 2023 Notes in February 2015.
The terms of the Revolver require the Company to make periodic payments of interest on the
loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the
maturity date thereof. The Revolver is subject to a borrowing base which limits the amount of
borrowings which may be drawn thereunder. The borrowing base will be redetermined by the lenders at
least semi-annually on or about April 1 and October 1 of each year. Interest on the Revolver is
calculated, at the Company’s option, at either (a) the LIBO rate for the applicable interest period plus
a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the
greatest of the federal funds rate plus 0.50%, the one-month adjusted LIBO rate plus 1.00%, or the
prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of
0.50% to 1.50% based on the level of borrowing base utilization at such time. For the year ended
December 31, 2014, the average interest rate under the Revolver was 2.51% on an average outstanding
balance of $333.8 million. 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.
Total interest and commitment fees under the Revolver and Term Loan were $13.0 million,
$27.0 million, and $21.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.
$3.8 million in unamortized deferred financing costs were charged to interest expense during 2014 in
connection with repayment of the Term Loan.
The Revolver is 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 approximates
fair value, as it is subject to short-term floating interest rates that approximate the rates available to the
Company for those periods.
We are subject to certain covenants under the Revolver which include, but are not limited to,
restrictions on asset sales, distributions to members, and incurrence of additional indebtedness, and
financial covenants which require the maintenance of certain financial ratios, including a maximum
leverage ratio, and a minimum current ratio. The Company was in compliance with these covenants at
December 31, 2014.
F-25
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
7. Stock-based Compensation
Management Units
Prior to the IPO, JEH granted management units under a previously existing management
incentive plan. 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, 2014, there
were 274,385 unvested JEH Units and shares of Class B common stock under this plan. No new JEH
Units and Class B shares are created upon a vesting event. The JEH Units (together with a
corresponding number of shares of Class B common stock) will become exchangeable into a like
number of shares of Class A common stock upon vesting or forfeiture. The following table summarizes
information related to the vesting of JEH Units:
Unvested at January 1, 2013 . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested at December 31, 2013 . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
JEH Units
710,767
911,654
(167,239)
(998,032)
457,150
21,405
(21,405)
(182,765)
Unvested at December 31, 2014 . . . . . . . . . . . . . . . . . . .
274,385
Weighted Average
Grant Date Fair
Value
per Share
$ 3.62
$15.00
$ 3.62
$ 9.96
$12.46
$ 6.66
$ 6.66
$ 8.65
$15.00
Stock compensation expense associated with the management units and JEH Units for the years
ended December 31, 2014, 2013 and 2012 was $1.6 million, $10.7 million, and $0.6 million, respectively,
and is included in general and administrative expenses on the Company’s Consolidated Statement of
Operations.
Restricted Stock Awards
On September 23, 2014, the Company granted restricted stock awards to non-employee members
of the Board of Directors. Each of the five directors was awarded 5,486 restricted shares of Class A
common stock, contingent on the director serving as a director of the Company for a one-year service
period in accordance with the terms of the award. The fair value of the awards was based on the value
of the Company’s Class A common stock on the date of grant.
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
F-26
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
7. Stock-based Compensation (Continued)
Class A common stock on the date of grant. These awards are fully vested as of December 31, 2014.
The total number of shares awarded to the directors is as follows:
Director Restricted Stock Awards
Restricted
Stock Awards
Weighted Average
Grant Date Fair
Value per Share
Unvested at January 1, 2013 . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested at December 31, 2013 . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
26,580
—
—
26,580
27,430
—
(26,580)
Unvested at December 31, 2014 . . . . . . . . . . . . . . . . .
27,430
—
$15.05
—
—
$15.05
$18.77
—
$15.05
$18.77
Stock compensation expense associated with the Board of Directors awards for the year ended
December 31, 2014 was $0.4 million and 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.
Restricted Stock Unit Awards
During the year ended December 31, 2014, the Company granted 340,001 restricted stock unit
awards to certain officers and employees of the Company. The fair value of the restricted stock unit
awards 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 applicable three-year vesting period. The total number of
units awarded to the officers and employees is as follows:
Employee Restricted Stock Unit Awards
Restricted Weighted Average
Grant Date Fair
Stock Unit
Value per Share
Awards
Unvested at January 1, 2014 . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
340,001
(13,688)
(1,416)
Unvested at December 31, 2014 . . . . . . . . . . . . . . . . . . .
324,897
—
$17.31
$17.07
$17.07
$17.33
Stock compensation expense associated with the employee restricted stock unit awards for the
twelve months ended December 31, 2014 was $1.1 million, and is included in general and
administrative expenses on the Company’s Consolidated Statement of Operations.
F-27
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
7. Stock-based Compensation (Continued)
Performance Unit Awards
During the twelve months ended December 31, 2014, the Company granted 201,318 performance
unit awards to certain officers of the Company. Upon the completion of the applicable three-year
performance period, each officer will vest in a number of performance units. The number of
performance units in which each officer vests at such time will range from 0% to 200% based on the
Company’s total shareholder return relative to an industry peer group over the applicable three-year
performance period. Each vested performance unit is exchangeable for one share of the Company’s
Class A common stock. The grant date fair value of the performance units was determined using a
Monte Carlo simulation model, which results in an expected percentage of performance units earned.
The fair value of the performance units is expensed on a straight-line basis over the applicable
three-year performance period.
The total number of units awarded to the officers is as follows:
Employee Performance Unit Awards
Performance
Unit Awards
Weighted Average
Grant Date Fair
Value per Share
Unvested at January 1, 2014 . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
201,318
(8,320)
—
Unvested at December 31, 2014 . . . . . . . . . . . . . . . . . .
192,998
—
$21.65
$21.65
—
$21.65
Stock compensation expense associated with the performance unit awards for the twelve months
ended December 31, 2014 was $0.9 million, and is included in general and administrative expenses on
the Company’s Consolidated Statement of Operations.
The Monte Carlo simulation process is a generally accepted statistical technique used, in this
instance, to simulate future stock prices for the Company and the components of the peer group. The
simulation uses a risk-neutral framework along with the risk-free rate of return, the volatility of each
entity, and the correlations of each entity with the other entities in the peer group. A stock price path
has been simulated for the Company and each peer company and is used to determine the payout
percentages and the stock price of the Company’s common stock as of the vesting date. The ending
stock price is multiplied by the payout percentage to determine the projected payout, which is then
discounted with the risk-free rate of return to the grant date to determine the grant date fair value for
that simulation. When enough simulations are generated, the resulting distribution gives a reasonable
estimate of the range of future expected stock prices.
F-28
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
7. Stock-based Compensation (Continued)
The following assumptions were used for the Monte Carlo simulation model to determine the
grant date fair value and associated compensation expense during the twelve months ended
December 31, 2014:
Stock Price(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Beginning Average Stock Price(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected Volatility(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-Free Rate of Return(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17.07
$14.78
46.95%
0.61%
(1) Based on the closing price of Jones Energy, Inc. Class A common stock on May 20, 2014.
(2) Based on the 10 trading days immediately prior to the beginning of the performance
period.
(3) Based on the average historical volatilities over the most recent 2.62-year period for the
Company and each peer company using daily stock prices through May 20, 2014. The
measurement period reflects the 2.62 years remaining in the performance period as of the
grant date.
(4) Based on the yield curve of U.S. Treasury rates as of May 20, 2014.
Based on these assumptions, the Monte Carlo simulation model resulted in a simulated fair value
of $21.65 based on an expected percentage of performance units earned of 126.80%.
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. Shares of Class B common stock are not included in the calculation of earnings per
share because they are not participating securities and have no economic interest in the Company.
Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued
by the Company in conjunction with stock awards that have been granted to directors and employees.
In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be considered
outstanding as of the respective grant dates for purposes of computing diluted EPS even though the
award is contingent upon vesting. For the twelve months ended December 31, 2014, 27,430 restricted
stock shares, 54,656 restricted stock units and 192,998 performance units were excluded from the
calculation as they would have had an anti-dilutive effect. The following is a calculation of the basic
and diluted weighted-average number of shares of Class A common stock outstanding and EPS. 2014 is
calculated using the twelve months ended December 31, 2014. 2013 is calculated for the period from
July 29, 2013, the closing date of the IPO, to December 31, 2013.
F-29
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
8. Earnings per Share (Continued)
Basic Earnings per Share
(in thousands, except per share data)
Income (numerator):
2014
2013
Net income (loss) attributable to controlling interests . . . . . . .
$40,868
$ (2,186)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock .
12,526
12,500
Earnings (loss) per share:
Basic earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3.26
$ (0.17)
Diluted Earnings per Share
(in thousands, except per share data)
Income (numerator):
2014
2013
Net income (loss) attributable to controlling interests . . . . . . .
$40,868
$ (2,186)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock .
12,535
12,500
Earnings (loss) per share:
Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3.26
$ (0.17)
Anti-dilutive shares of Class A common stock . . . . . . . . . . . . . .
275
27
9. Monarch Investment
On May 7, 2013, the Company entered into a marketing agreement with 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. During the year ended December 31, 2014,
$0.5 million of the equity interests were distributed to management under the incentive plan. The
Company recognized expense of $0.8 million during the year ended December 31, 2014 and
$0.3 million during the year ended December 31, 2013 in connection with the incentive plan. In
addition, the Company recorded deferred revenue of $15.0 million related to the marketing agreement
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 $1.2 million of the deferred
revenue balance during the year ended December 31, 2014, and $0.5 million of deferred revenue during
the year ended December 31, 2013. This revenue is recorded in other revenues on the Company’s
Consolidated Statement of Operations.
F-30
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
10. Commitments and Contingencies
Lease obligations
The Company leases approximately 43,000 square feet of office space in Austin, TX under an
operating lease arrangement. Future minimum payments for all noncancellable operating leases
extending beyond one year at December 31, 2014 are as follows:
(in thousands of dollars)
Years Ending December 31,
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 944
954
1,038
1,101
1,122
377
$5,536
Rent expense under operating leases was $0.9 million, $0.8 million and $0.8 million for the years
ended December 31, 2014, 2013 and 2012, 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 each of the years ended December 31, 2014 and 2013, $0.3 million was contributed
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 each of the years ended December 31, 2014 and 2013, the Company made
no contributions 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-31
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
12. Income Taxes (Continued)
franchise tax expense. The following table summarizes the tax provision for the years ended
December 31, 2014, 2013 and 2012:
(in thousands of dollars)
Current tax expense:
Year Ended December 31,
2014
2013
2012
Federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
53
—
53
85
—
85
$ —
—
—
Deferred tax expense (benefit):
Federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred expense (benefit) . . . . . . . . . . . . . . . . . . .
21,996
4,025
26,021
(1,260) —
473
1,104
(156)
473
Total tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . .
$26,074
$
(71) $473
Tax expense (benefit) attributable to controlling interests .
Tax expense attributable to non-controlling interests . . . . .
$22,675
3,399
$(1,223) $473
—
1,152
Total income tax expense (benefit) . . . . . . . . . . . . . . . . .
$26,074
$
(71) $473
For the pre-IPO period of the year ended December 31, 2013 and for the entire year ended
December 31, 2012, the reported taxes in the table above 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:
2014
2013
Net income before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statutory rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$250,217
$22,334
35%
35%
Income tax expense computed at statutory rate . . . . . . . . . . .
Less: Non-controlling interests . . . . . . . . . . . . . . . . . . . . .
$ 87,577
(65,336)
$ 7,817
(9,009)
Income tax expense (benefit) attributable to controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State and local income taxes, net of federal benefit . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax expense (benefit) attributable to controlling interests
Tax expense attributable to non-controlling interests . . . . . . .
22,241
626
(192)
22,675
3,399
(1,192)
(49)
18
(1,223)
1,152
Total income tax expense (benefit) . . . . . . . . . . . . . . . . .
$ 26,074
$
(71)
For the year ended December 31, 2012, the calculation is not applicable as the Company was not
subject to federal income taxes prior to the IPO.
F-32
Jones Energy, Inc.
Notes to the 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,
2014
2013
Investment in consolidated subsidiary JEH . . . . . . . . . . . . . .
Net operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Section 754 election tax basis adjustment . . . . . . . . . . . . . . . .
Alternative minimum tax credits . . . . . . . . . . . . . . . . . . . . . .
Other deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities
Current state deferred tax liability . . . . . . . . . . . . . . . . . . . . .
Investment in consolidated subsidiary JEH . . . . . . . . . . . . . .
Noncurrent state deferred tax liability . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . .
$
— $
8,223
945
53
232
9,453
718
29,163
6,731
36,612
526
649
—
86
52
1,313
—
—
3,093
3,093
Net deferred tax assets (liabilities) . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(27,159)
—
(1,780)
—
Net deferred tax assets (liabilities) . . . . . . . . . . . . . . . . .
$(27,159) $(1,780)
The Company has a federal net operating loss carry-forward totaling $22.4 million and state net
operating loss carry-forward of $9.6 million, both of which expire between 2033 and 2034. 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. In addition, the Company may elect to capitalize intangible drilling costs,
rather than expensing these costs, in order to prevent an operating loss carryforward 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 2010 through 2014. The tax
years 2011 through 2014 remain open to examination by the major taxing jurisdictions to which the
Company is subject. The Company is not currently under audit by the IRS or any state 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, 2014 and December 31, 2013 there was no
material liability or expense for the periods then ended recorded for payments of interest and penalties
F-33
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
12. Income Taxes (Continued)
associated with uncertain tax positions or material unrecognized tax positions and the Company’s
unrecognized tax benefits were not material.
Tax Receivable Agreement
JEH intends to make an election under Section 754 of the Internal Revenue Code (the ‘‘Code’’)
effective for 2014 and future tax years. As a result, JEH will be required to adjust the tax basis of the
assets of JEH at the time of an exchange of JEH units and Class B common stock held by the
non-controlling interest members of the Company for Class A common stock. The tax basis
adjustments are expected to result in increases in the tax basis of the assets of JEH that would
otherwise have not been available. This increase in tax basis allows the Company to reduce the amount
of future tax payments to the extent that the Company has future taxable income.
As a result of the increase in tax basis generated in exchanges made as of December 31, 2014, the
Company is entitled to future tax benefits of $0.9 million and has recorded this amount as a deferred
tax asset on its consolidated balance sheet. Under the terms of the TRA entered into prior to the IPO,
JEI will pay 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax that
the Company actually realizes as a result of these increases in tax basis to the exchanging member who
generated the increased tax basis. For purposes of making payments under the TRA, actual cash
savings in income tax in a given year will be computed by comparing the Company’s actual income tax
liability to the amount of such taxes the Company would have been required to pay had there been no
increase to the tax basis of the assets of JEH as a result of the exchanges.
While the actual amount and timing of payments under the TRA will depend upon a number of
factors, including the amount and timing of taxable income generated in the future, changes in future
tax rates, the value of individual assets, and the portion of the Company’s payments under the TRA
constituting imputed interest, the Company has estimated that the payments that will be made to the
pre-IPO members who have exchanged shares as of December 31, 2014 will be $0.8 million and has
recorded this obligation as a liability on the consolidated balance sheet. To the extent the Company
does not realize all of the tax benefits in future years or in the event of a change in future tax rates,
this liability may change.
As of December 31, 2014, the Company has not made any payments under the TRA to pre-IPO
members who have exchanged JEH units and Class B common stock for Class A common stock. The
Company does not anticipate making a material payment under the TRA in 2015.
13. Subsequent Events
Public Offering of Class A Common Stock
On February 17, 2015, the Company completed the issuance and sale of 7,500,000 shares of
Class A common stock to the public at a price of $10.25 per share under the Company’s registration
statement on Form S-3 (the ‘‘Public Equity Offering’’). The shares of Class A common stock were
issued pursuant to an underwriting agreement, dated February 11, 2015, in which the Company granted
the underwriters a 30-day option to purchase up to an additional 1,125,000 shares of Class A common
stock.
F-34
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
13. Subsequent Events (Continued)
Private Placement of Class A Common Stock
On February 23, 2015, the Company completed the sale of an aggregate of $50.0 million of its
Class A common stock to certain affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a
direct placement of registered shares under the Company’s registration statement on Form S-3 (the
‘‘Private Equity Offering’’). Under the terms of the Private Equity Offering, the Company sold
4,761,905 shares of Class A common stock at a purchase price of $10.50 per share.
Private Placement of Senior Unsecured Notes
On February 23, 2015, JEH and Jones Energy Finance Corp., a wholly-owned subsidiary of JEH
formed for the sole purpose of co-issuing certain of JEH’s debt, completed the sale of $250.0 million in
aggregate principal amount of 9.25% senior unsecured notes due 2023 (the ‘‘2023 Notes’’) to certain
affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a private placement (the ‘‘Notes
Offering’’). The 2023 Notes rank equally with all of the Company’s other senior unsecured
indebtedness and are effectively subordinated in right of payment to all of the Company’s secured
indebtedness (to the extent of the collateral securing such indebtedness). The 2023 Notes are fully and
unconditionally guaranteed on a senior unsecured basis by the Company and by all of JEH’s existing
subsidiaries (other than the co-issuer and two immaterial subsidiaries) and any future subsidiaries that
guarantee indebtedness under the Revolver or other debt securities.
The Company used the net proceeds from the Public Equity Offering, the Private Equity Offering
and the Notes Offering for working capital and to repay outstanding borrowings under the Revolver.
14. Subsidiary Guarantors
On April 1, 2014, JEH and its wholly-owned subsidiary, Jones Energy Finance Corp. (the
‘‘Issuers’’), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% Senior Notes due
2022 (the ‘‘2022 Notes’’).
The 2022 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s
current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain
future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the
Company’s Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full,
unconditional, and joint and several with all other subsidiary guarantees and the parent guarantee. Any
subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are minor.
The Company is a holding company and has no independent assets or operations of its own. The
Company is the sole managing member of JEH and is responsible for all operational, management and
administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company
agreement, the Company may not be removed as the sole managing member of JEH.
As of December 31, 2014, the Company held approximately 25.6% of the economic interest in
JEH, with the remaining 74.4% economic interest held by a group of investors that owned interests in
JEH prior to the Company’s IPO (the ‘‘Existing Owners’’). The Existing Owners have no voting rights
with respect to their economic interest in JEH.
The Company has two classes of common stock, Class A common stock, which was sold to
investors in the IPO, and Class B common stock. Pursuant to the Company’s certificate of
F-35
Jones Energy, Inc.
Notes to the Consolidated Financial Statements (Continued)
14. Subsidiary Guarantors (Continued)
incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of
Class A common stock are entitled to 100% of the economic interests in the Company. Each share of
Class B common stock has no economic rights in the Company, but entitles its holder to one vote on
all matters to be voted on by the Company’s stockholders generally.
In connection with a reorganization that occurred immediately prior to the IPO, each Existing
Owner was issued a number of shares of Class B common stock that is equal to the number of JEH
Units that such Existing Owner holds. Holders of the Company’s Class A common stock and Class B
common stock generally vote together as a single class on all matters presented to the Company’s
stockholders for their vote or approval. Accordingly, the Existing Owners collectively have a number of
votes in the Company equal to the aggregate number of JEH Units that they hold.
The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and
among the Company, JEH and each of the Existing Owners, to exchange their JEH Units (together
with a corresponding number of shares of Class B common stock) 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. As a result, the Company expects that
over time the Company will have an increasing economic interest in JEH as Class B common stock and
JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of
the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the
Company. The Company intends to retain full voting and management control over JEH.
F-36
Jones Energy, Inc.
Condensed Consolidating Balance Sheet
December 31, 2014
(in thousands of dollars)
Assets
Current assets
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net
Oil and gas sales . . . . . . . . . . . . . . . . . .
Joint interest owners . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . .
Commodity derivative assets
Other current assets
. . . . . . . . . . . . . . . . .
Intercompany receivable . . . . . . . . . . . . . . .
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
. . . . . . . . . . . . . . .
Investment in subsidiaries
JEI (Parent)
Issuers
Guarantor
Subsidiaries Subsidiaries Eliminations Consolidated
Non-
Guarantor
$
100
—
$
1,000
—
$
12,436
149
$
30
—
$
—
—
$
13,566
149
—
—
102
—
—
4,164
4,366
—
—
—
—
171
231,866
—
—
8,788
121,519
451
1,205,608
1,337,366
49,861
41,761
3,622
—
2,923
—
110,752
— 1,638,860
3,252
—
—
87,055
254
20,098
—
—
—
—
—
—
—
—
—
(2,328)
(2,298)
—
796
—
—
—
—
—
—
—
—
—
(1,207,444)
(1,207,444)
—
—
—
—
—
(231,866)
49,861
41,761
12,512
121,519
3,374
—
242,742
1,638,860
4,048
87,055
20,352
171
—
Total assets . . . . . . . . . . . . . . . . . . . .
$236,403
$1,444,519
$1,753,118
$(1,502)
$(1,439,310)
$1,993,228
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable . . . . . . . . . . . . . . . .
Oil and gas sales payable . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . .
Intercompany payable . . . . . . . . . . . . . . . .
$
— $
—
—
—
—
—
$ 136,049
288
70,469
—
10,487
8,914
—
718
—
3,074
— 1,209,630
$ —
—
—
—
—
—
Total current liabilities . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . .
Senior notes
. . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . .
Commodity derivative liabilities . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . .
Liability under tax receivable agreement . . . . . . .
. . . . . . . . . . . . . . . . .
Deferred tax liabilities
Total liabilities . . . . . . . . . . . . . . . . . .
Stockholders’ / members’ equity
Members’ equity . . . . . . . . . . . . . . . . . . . . .
Class A common stock, $0.001 par value;
12,672,260 shares issued and 12,649,658 shares
outstanding . . . . . . . . . . . . . . . . . . . . .
Class B common stock, $0.001 par value;
36,719,499 shares issued and outstanding . . .
Treasury stock, at cost; 22,602 shares . . . . . . .
Additional paid-in-capital
. . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . . . . . . .
Non-controlling interest . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . .
—
—
—
—
—
—
803
20,093
20,896
—
13
37
(358)
177,133
38,682
215,507
—
215,507
$
—
—
—
—
—
(1,209,630)
(1,290,630)
—
—
—
—
—
—
—
$ 136,337
70,469
19,401
718
3,074
—
229,999
360,000
500,000
13,377
28
10,536
803
26,612
(1,209,630)
1,141,355
9,920
360,000
500,000
13,377
28
—
—
6,519
1,429,709
—
—
—
—
10,536
—
—
889,844
1,440,245
—
—
—
—
—
—
—
—
—
554,675
312,873
(1,502)
(866,046)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
554,675
—
554,675
312,873
—
312,873
(1,502)
—
(1,502)
(866,046)
636,366
(229,680)
—
13
37
(358)
177,133
38,682
215,507
636,366
851,873
Total liabilities and stockholders’ equity . . .
$236,403
$1,444,519
$1,753,118
$(1,502)
$(1,439,310)
$1,993,228
F-37
Jones Energy, Inc.
Condensed Consolidating Balance Sheet
December 31, 2013
Total assets . . . . . . . . . . . . . .
$171,120
$1,106,095
$1,430,915
$
(in thousands of dollars)
Assets
Current assets
Cash . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . .
Accounts receivable, net
Oil and gas sales . . . . . . . . . . . .
Joint interest owners
. . . . . . . . .
Other . . . . . . . . . . . . . . . . . . .
Commodity derivative assets . . . . . .
Other current assets . . . . . . . . . . .
Deferred tax assets . . . . . . . . . . . .
Intercompany receivable . . . . . . . .
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 . . . . . . . . . . . . . . . . . .
Investment in subsidiaries . . . . . . . . .
Deferred tax assets . . . . . . . . . . . . .
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable . . . . . . . . .
Oil and gas sales payable . . . . . . . .
Accrued liabilities . . . . . . . . . . . . .
Commodity derivative liabilities . . . .
Asset retirement obligations . . . . . .
Intercompany payable . . . . . . . . . .
Total current liabilities . . . . . . .
Long-term debt
. . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . .
Commodity derivative liabilities
. . . . .
Asset retirement obligations . . . . . . . .
Deferred tax liabilities . . . . . . . . . . .
Total liabilities . . . . . . . . . . . .
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’ equity . . . . . . . . . . . . .
. . . . . . . . . .
Non-controlling interest
Total stockholders’ equity . . . . .
Total liabilities and stockholders’
equity . . . . . . . . . . . . . . . .
JEI (Parent)
Issuers
Guarantor Non-Guarantor
Subsidiaries
Subsidiaries
Eliminations Consolidated
$
100
—
—
—
—
—
—
—
638
738
—
$
6,000
—
$
17,650
45
$
—
—
—
8,837
387
12
1,051,389
1,066,625
51,233
42,481
16,782
—
2,005
—
—
130,196
— 1,297,228
—
—
—
169,081
1,301
—
25,398
14,072
—
—
2,557
—
934
—
—
70
—
—
—
—
—
—
—
70
—
887
—
—
—
—
957
$
— $
—
23,820
45
—
—
—
—
—
—
(1,052,027)
51,233
42,481
16,782
8,837
2,392
12
—
(1,052,027)
145,602
—
1,297,228
—
—
—
(169,081)
—
3,444
25,398
15,006
—
1,301
$(1,221,108)
$1,487,979
$
— $
—
87
—
—
—
$
89,200
230
66,179
—
9,076
1,642
—
10,664
—
2,590
— 1,051,935
12,536
658,000
14,531
190
—
3,093
1,218,980
—
—
—
8,373
—
688,350
1,227,353
$ —
—
—
—
—
2,279
2,279
—
—
—
—
—
2,279
$
— $
—
—
—
—
(1,054,214)
(1,054,214)
—
—
—
—
—
(1,054,214)
417,745
203,562
(1,322)
(619,985)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
417,745
—
417,745
203,562
—
203,562
(1,322)
—
(1,322)
(619,985)
453,091
(166,894)
87
—
—
—
—
—
87
—
13
37
173,169
(2,186)
171,033
—
171,033
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
$171,120
$1,106,095
$1,430,915
$
957
$(1,221,108)
$1,487,979
F-38
Jones Energy, Inc.
Condensed Consolidating Statement of Operations and Comprehensive Income
Year Ended December 31, 2014
(in thousands)
Operating revenues
Oil and gas sales . . . . . . . . .
Other revenues . . . . . . . . . .
Total operating revenues .
Operating costs and
expenses
Lease operating . . . . . . . . .
Production taxes . . . . . . . . .
Exploration . . . . . . . . . . . .
Depletion, depreciation and
amortization . . . . . . . . . .
Accretion of discount . . . . .
General and administrative
(including non-cash
compensation expense) . .
Total operating expenses .
Operating income . . . . . .
Other income (expense)
Interest expense . . . . . . . . .
Net gain on commodity
derivatives . . . . . . . . . . . .
Gain on sales of assets . . . .
Other income (expense),
net . . . . . . . . . . . . . . .
Income (loss) before
income tax . . . . . . . . . .
JEI (Parent)
Issuers
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
Eliminations
Consolidated
$ — $
—
— $378,401
1,042
1,154
$ —
—
—
$
— $378,401
2,196
—
—
380,597
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,154
379,443
—
—
—
43,843
18,094
3,453
— 181,578
770
—
4,494
4,494
21,180
268,918
—
—
—
91
—
89
180
(3,340)
110,525
(180)
(45,215)
(1,511)
189,641
—
—
297
144,426
(1,214)
—
—
—
—
141,086
109,311
(180)
—
—
—
—
—
—
—
—
—
—
—
—
—
43,843
18,094
3,453
181,669
770
25,763
273,592
107,005
(46,726)
189,641
297
143,212
250,217
Equity interest in income . .
62,785
—
—
—
(62,785)
—
Income tax provision
Current . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . .
Total income tax provision
Net income (loss) . . . . . . . .
Net income attributable to
non-controlling interests . .
Net income attributable to
53
21,864
21,917
40,868
—
controlling interests . . . . .
$40,868
4,157
4,157
—
136,929
109,311
—
—
—
—
—
(180)
—
—
53
26,021
26,074
—
(62,785)
224,143
183,275
183,275
— $ 40,868
F-39
Jones Energy, Inc.
Condensed Consolidating Statement of Operations and Comprehensive Income
Year Ended December 31, 2013
JEI (Parent)
Issuers
Guarantor
Subsidiaries Subsidiaries Eliminations Consolidated
Non-
Guarantor
$ — $
—
— $258,063
637
469
$ —
—
$ — $258,063
1,106
—
(in thousands)
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 (loss) on sales of assets . . . .
—
—
—
—
—
—
—
—
—
—
469
258,700
—
—
—
27,781
12,865
1,710
— 114,046
—
—
14,415
608
—
—
—
—
90
—
—
4,154
4,154
27,490
198,915
258
348
(3,685)
59,785
(348)
— (29,653)
(1,121)
—
—
—
(2,566)
—
—
41
Other income (expense), net . . .
— (32,219)
(1,080)
Income (loss) before income tax
— (35,904)
58,705
Equity interest in income . . . . . . .
(3,400)
—
Income tax provision (benefit)
Current . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . .
85
(1,299)
1,143
Total income tax provision
(benefit) . . . . . . . . . . . . . . .
(1,214)
1,143
—
—
—
—
—
(119)
(119)
(467)
—
—
—
—
Net income (loss) . . . . . . . . . . . .
Net income attributable to
(2,186)
(37,047)
58,705
(467)
3,400
22,405
non-controlling interests . . . . . .
—
Net income (loss) attributable to
controlling interests . . . . . . . . .
$(2,186)
—
—
—
—
—
—
24,591
24,591
— $ (2,186)
F-40
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
259,169
27,781
12,865
1,710
114,136
14,415
608
31,902
203,417
55,752
(30,774)
(2,566)
(78)
(33,418)
22,334
3,400
—
—
—
—
85
(156)
(71)
Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2014
(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
Net cash (used in) / provided
JEI (Parent)
Issuers
Guarantor
Subsidiaries Subsidiaries Eliminations Consolidated
Non-
Guarantor
$ 40,868
$ 136,929 $ 109,311
$(180)
$(62,785)
$ 224,143
(40,510)
(326,859)
345,724
140
62,785
41,280
by operations . . . . . . . . . . .
358
(189,930)
455,035
(40)
—
265,423
Cash flows from investing
activities
Additions to oil and gas
properties . . . . . . . . . . . . . . .
Net adjustments to purchase
price of properties acquired . .
Proceeds from sales of assets . . .
Acquisition of other property,
plant and equipment
. . . . . . .
Current period settlements of
matured derivative contracts . .
Change in restricted cash . . . . . .
Net cash (used in) / provided
by investing . . . . . . . . . . . .
Cash flows from financing
activities
Proceeds from issuance of
long-term debt . . . . . . . . . . . .
Repayment under long-term debt
Proceeds from senior notes . . . .
Payment of debt issuance costs . .
Purchase of treasury stock . . . . .
Net cash (used in) / provided
—
—
—
—
—
—
—
— (474,619)
—
—
—
15,709
448
(1,683)
(3,654)
—
—
(104)
(3,654)
(460,249)
—
170,000
— (468,000)
500,000
—
(13,416)
—
—
(358)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
by financing . . . . . . . . . . . .
(358)
188,584
Net increase (decrease) in
cash . . . . . . . . . . . . . . . . . .
Cash
Beginning of period . . . . . . . . . .
End of period . . . . . . . . . . . . . .
$
—
100
100
(5,000)
(5,214)
(40)
6,000
17,650
70
— (474,619)
—
—
—
—
—
15,709
448
(1,683)
(3,654)
(104)
— (463,903)
—
170,000
— (468,000)
500,000
—
(13,416)
—
(358)
—
—
—
—
188,226
(10,254)
23,820
$
1,000 $ 12,436
$ 30
$
— $ 13,566
F-41
Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013
(in thousands of dollars)
Cash flows from operating
activities
JEI (Parent)
Issuers
Guarantor
Subsidiaries Subsidiaries Eliminations Consolidated
Non-
Guarantor
(2,186) $ (37,047) $ 58,705
$(467)
$
3,400
$ 22,405
2,286
(189,393)
315,942
by operations . . . . . . . . . . .
100
(226,440)
374,647
Net income (loss) . . . . . . . . . . . $
Adjustments to reconcile net
income (loss) to net cash
provided by operating activities
Net cash (used in) / provided
Cash flows from investing
activities
Investment in subsidiary . . . . . . .
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 . . . . . .
Net cash (used in) / provided
733
266
—
—
—
644
(3,400)
126,168
—
148,573
172,481
—
— (197,618)
— (178,173)
1,607
—
—
—
—
(1,634)
7,586
(45)
(172,481)
—
—
—
—
—
—
—
—
— (197,618)
— (178,173)
963
—
—
(724)
(910)
7,586
—
—
(45)
—
—
by investing . . . . . . . . . . . .
(172,481)
7,586
(375,597)
(266)
172,481
(368,277)
Cash flows from financing
activities
Proceeds from investment in JEI
Proceeds from issuance of
long-term debt . . . . . . . . . . . .
Repayment under long-term debt
Payment of debt issuance costs . .
Proceeds from sale of common
stock, net of expenses of
$15.1 million . . . . . . . . . . . . .
Net cash (used in) / provided
— 172,481
— 220,000
— (172,000)
(683)
—
172,481
—
by financing . . . . . . . . . . . .
172,481
219,798
—
—
—
—
—
—
Net increase (decrease) in
cash . . . . . . . . . . . . . . . . . .
Cash
Beginning of period . . . . . . . . . .
100
—
944
(950)
5,056
18,600
—
—
—
—
—
—
—
70
(172,481)
—
220,000
(172,000)
(683)
172,481
(172,481)
219,798
—
—
94
23,726
End of period . . . . . . . . . . . . . . $
100 $
6,000 $ 17,650
$ 70
$
— $ 23,820
F-42
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)
Property acquisitions:
2014
2013
2012
Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement costs . . . . . . . . . . . . . . . . . . . . . .
$ 20,030
10,101
3,453
488,076
1,908
$ 35,943
142,230
1,710
240,412
1,822
$ 69,725
182,200
356
125,493
662
Total costs incurred . . . . . . . . . . . . . . . . . . . . . .
$523,568
$422,117
$378,436
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 . . . . . . . . . . . . . . .
2014
2013
$
94,526
2,095,396
$
99,134
1,568,564
2,189,922
(551,062)
1,667,698
(370,470)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,638,860
$1,297,228
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, 2014, 2013 and 2012. 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-43
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, 2011 . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . .
Purchases of minerals in place . . . . . .
Sales of minerals in place . . . . . . . . . .
Revisions of previous estimates . . . . . .
December 31, 2012 . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . .
Purchases of minerals in place . . . . . .
Sales of minerals in place . . . . . . . . . .
Revisions of previous estimates . . . . . .
December 31, 2013 . . . . . . . . . . . . . . . .
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)
7,440
286
(742)
6,056
(8)
(492)
12,540
3,786
(1,557)
3,275
—
(1,356)
16,688
9,295
(2,475)
3,180
—
995
34,606
1,766
(1,770)
5,799
(53)
(5,602)
34,746
5,710
(1,724)
4,418
—
(10,235)
32,915
8,675
(2,345)
3,073
—
(3,448)
244,579
11,727
(13,980)
36,842
(309)
(50,779)
228,080
39,799
(17,575)
35,023
583
(49,262)
236,648
59,248
(21,922)
22,943
—
(4,640)
82,810
4,007
(4,842)
17,995
(113)
(14,557)
85,300
16,129
(6,210)
13,530
97
(19,801)
89,045
27,844
(8,474)
10,077
—
(3,226)
December 31, 2014 . . . . . . . . . . . . . . . .
27,683
38,870
292,277
115,266
Revision of previous estimates
For the year ended December 31, 2014, the Company had net negative revisions of 3,226 MBoe, of
which 3,534 MBoe was related to production performance in the Woodford basin. The remaining net
positive revisions of 308 MBoe were primarily related to production performance in the Cleveland
basin and other changes.
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.
F-44
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.
Crude Oil
(MBbls)
NGL
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)(1)
Estimated Proved Reserves
December 31, 2012
Proved developed . . . . . . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . .
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
December 31, 2014
Proved developed . . . . . . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . .
10,773
16,910
Total proved reserves . . . . . . . . . . . . .
27,683
16,320
18,426
34,746
19,101
13,814
32,915
22,555
16,315
38,870
110,956
117,124
228,080
139,623
97,025
236,648
160,877
131,400
292,277
39,075
46,225
85,300
49,501
39,544
89,045
60,141
55,125
115,266
(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:
• future costs and sales prices will probably differ from those required to be used in these
calculations;
• actual production rates for future periods may vary significantly from the rates assumed in the
calculations;
• future tax rates, deductions and credits are calculated under current laws, which may change in
future years;
• 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, 2014, 2013 and 2012. 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-45
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 . . . . . . . . . . . . . . . . . . .
2014
2013
2012
$ 5,038,212
$3,213,718
$2,746,767
Less related future:
Production costs . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . .
(1,216,184)
(939,652)
(199,727)
(734,974)
(549,343)
(129,497)
(612,054)
(529,692)
—
Future net cash flows . . . . . . . . . . . . . . . . . .
10% annual discount for estimated timing of
2,682,649
1,799,904
1,605,021
cash flows . . . . . . . . . . . . . . . . . . . . . . . .
(1,294,553)
(859,395)
(823,001)
Standardized measure of discounted future
net cash flows . . . . . . . . . . . . . . . . . . . . .
$ 1,388,096
$ 940,509
$ 782,020
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 . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014
2013
2012
$ 940,509
$ 782,020
$ 915,807
98,647
(96,245)
77,280
(9,706)
(336,855)
67,495
(382,202)
442,340
(224,739)
239,844
(119,931)
37,723
118,562
—
149,619
(337)
197,740
(1,578)
43,032
(168,438)
(144,901)
163,739
(36,514)
94,051
2,177
110,783
(76,965)
59,621
1,527
99,513
—
91,581
(24,574)
Balance, end of period . . . . . . . . . . . . . . . . . . .
$1,388,096
$ 940,509
$ 782,020
Supplemental Quarterly Financial Information (Unaudited)
Restatement of Previously Issued Unaudited Quarterly Financial Statements
As part of our fourth quarter closing procedures, we identified an error in our previously issued
2014 quarterly financial statements which would have been material to such statements if not restated.
Therefore we have restated our Supplemental Quarterly Financial Information for the quarters ended
March 31, 2014, June 30, 2014 and September 30, 2014 as a result of an error in the calculation of
F-46
depletion, depreciation and amortization included in Jones’ consolidated financial statements. The
Company inadvertently classified capital expenditures related to nine new wells as Arkoma assets rather
than Anadarko assets leading to a miscalculation of depletion rates. This incorrect classification
resulted in the understatement of depletion, depreciation and amortization expense and the
overstatement of oil and gas properties in the amount of $1.9 million, $2.5 million and $2.6 million for
the quarters ended March 31, 2014, June 30, 2014 and September 30, 2014, respectively. As a result,
net income (loss) decreased for the quarters ended March 31, 2014, June 30, 2014 and September 30,
2014 by $1.7 million, $2.3 million, and $2.2 million, respectively. The balance sheet restatement resulted
in increases in accumulated depletion in the same amounts for each of the same periods. These
restatements had no impact on our net cash provided by operations in our Consolidated Statement of
Cash Flows. Restatements to the three month period ended March 31, 2014, the three and six month
periods ended June 30, 2014 and the three and nine month periods ended September 30, 2014 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, 2015, June 30, 2015 and September 30, 2015, respectively.
The impact of the restatement will be noted in Form 10-Q filings for 2015 and is summarized in
the table below:
2014 Three Months Ended
As
Reported
First
Quarter
As
Restated
First
Quarter
As
Reported
Second
Quarter
As
Restated
Second
Quarter
As
Reported
Third
Quarter
As
Restated
Third
Quarter
$1,363,393
$1,361,538
$1,449,765
$1,445,322
$1,533,704
$1,526,735
$
$
$
$
$
$
$
39,345
35,872
9,388
$
$
$
41,200
34,017
7,708
$
$
$
$
43,211
38,702
$
(9,184) $ (11,455) $
45,799
36,114
$
$
47,965
28,757
52,230
$
$
$
50,491
26,231
50,024
7,715
$
6,339
$
(7,537) $
(9,398) $
42,701
$
40,893
1,673
0.13
0.13
$
$
$
1,369
0.11
0.11
$
$
$
(1,647) $
(0.13) $
(2,057) $
(0.16) $
9,529
0.76
(0.13) $
(0.16) $
0.76
$
$
$
9,131
0.73
0.73
(in thousands)
Oil and gas properties . . .
Depletion, depreciation
and amortization . . . . .
Operating income . . . . . .
Net income (loss) . . . . . .
Net income (loss)
attributable to
non-controlling
interests . . . . . . . . . . .
Net income (loss)
attributable to
controlling interests . . .
Basic earnings per share .
Diluted earnings per
share . . . . . . . . . . . . .
The calculations of EBITDAX included in the Company’s previously filed consolidated financial
statements for the first three quarters of 2014 remain unchanged as a result of the restatements set
forth herein.
F-47
Following is a summary of the Company’s results of operations by quarter for the years ended
December 31, 2014 and 2013.
(in thousands except per share data)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to
(Restated)
First
Quarter
(Restated)
Second
Quarter
2014
(Restated)
Third
Quarter
$98,244
34,017
7,708
$106,390
36,114
(11,455)
$100,346
26,231
50,024
Fourth
Quarter
$ 75,617
10,643
177,866
Full
Year
$380,597
107,005
224,143
non-controlling interests
. . . . . . . . . . . . . . .
6,339
(9,398)
40,893
145,441
183,275
Net income (loss) attributable to controlling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic earnings per share . . . . . . . . . . . . . . . . .
Diluted earnings per share . . . . . . . . . . . . . . .
1,369
0.11
0.11
$
$
(2,057)
$
$
(0.16) $
(0.16) $
9,131
0.73
0.73
32,425
2.58
2.58
$
$
40,868
3.26
3.26
$
$
(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 earnings (loss) per share . . . . . . . . . . . . . . .
Diluted earnings (loss) 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
(7,751)
(1,326)
(14,623)
(860)
(0.07) $ (0.10) $
(0.07) $ (0.10) $
$
$
24,591
(2,186)
(0.17)
(0.17)
F-48
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 fact, 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.
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:
J O N e s e N e r G y, I N c .
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 28,
2015.
MANAGEMENT
J O N N y J O N e s
Founder, Chairman
& Chief Executive Officer
M I K e s . M c c O N N e l l
President
r O B e r t J . B r O O K s
Executive Vice President
& Chief Financial Officer
e r I c N I c c u M
Executive Vice President
& Chief Operating Officer
K r I s t e l F r a N K l I N
Sr. Vice President – Resources
H a l H aw t H O r N e
BOARD OF DIRECTORS
J O N N y J O N e s
Chairman
a l a N D . B e l l
Director
H O wa r D I . H O F F e N
Director
M I K e s . M c c O N N e l l
Director
G r e G O r y D . M y e r s
Director
r O B B l . v O y l e s
Director
H a l wa s H B u r N
Sr. Vice President – New Ventures
Director
s t e p H e N r O B e r t s
Sr. Vice President – Drilling
& Completions
J e F F ta N N e r
Sr. Vice President – Geosciences
t O D D w e H N e r
Sr. Vice President
& Chief Accounting Officer
D av I D c a p e
VP – Land and Business Development
D e N N I s c O r K r a N
VP – Production, Operations, and HSE
t H O M a s H e s t e r
VP – Finance
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
and Trust Company
6201 15th Avenue
Brooklyn, NY 11219
www.amstock.com
4/6/15 2:28 PM
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
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2
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1
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4
4
A
A
N
N
N
N
U
U
A
A
L
L
R
R
E
E
P
P
O
O
R
R
T
T
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