2015annual report
Built to
ProsPer
NYSE: SN
CorPorate offiCe,
Houston, texas
Sanchez Energy Corporation (NYSE: SN) is an independent
exploration and production company focused on the
acquisition and development of unconventional oil and
natural gas resources in the onshore U.S. Gulf Coast, with
a current focus on the Eagle Ford Shale in South Texas,
where we have accumulated approximately 200,000 net
leasehold acres, and the Tuscaloosa Marine Shale.
Built to ProsPer Built to ProSPEr
to our FEllow SharEholdErS:
2015 HigHligHts
» Record annual production of 19.2 MMBoe
for an average annual production rate of
~52,500 Boe/d, an increase of 72% over 2014
production
» Upstream capital expenditures of $545
million in 2015 compared to $867 million in
2014, a reduction of ~37% over 2014
» $155 million mark-to-market value of hedging
position at year-end 2015 corresponding
to hedge contracts covering ~82% of
expected 2016 revenues
MMBoe, with a PV-10 of $594 million
» 2015 year-end proved reserves are ~128
» Ended the year with a $435 million cash
balance and $735 million in total liquidity
This past year, Sanchez Energy delivered remarkable
financial and operating results while taking decisive
action to ensure the Company is well-positioned for
the future. The operating environment in 2015 was
characterized by significant commodity price volatility,
distress in the capital markets, and considerable
uncertainty with respect to the future of our industry.
However, by improving our financial position,
optimizing our asset base, lowering our cost structure,
and leveraging our competitive strengths, we believe
we are well situated to navigate today’s challenging
environment and prosper in the years ahead.
strong finanCial Position
Financial Discipline
Liquidity is important to our business, as it provides the
“runway” needed to manage through the current down
cycle and the resources required to capitalize on new
opportunities emerging from distress in the marketplace.
In 2015 we executed a focused and disciplined strategic
plan that allowed us to enter 2016 with approximately
$435 million in cash. That cash, together with borrowing
capacity under our credit facility, provided $735 million
of total liquidity as we entered 2016. Importantly, we
achieved this strong financial position without accessing
the capital markets in 2015.
Our strong financial position is the result of two key
strategic initiatives executed in 2015. First, because we
have been successful at increasing well productivity at
lower costs, we reduced upstream capital spending,
including accruals, by approximately 37% in 2015 compared
to 2014. Second, we completed the sale of two assets
in 2015, which resulted in total cash consideration of
approximately $430 million to Sanchez Energy.
Because we currently have no debt outstanding under our credit facility, no long
term debt maturing before 2021, and no maintenance covenants impeding our
operating plans, we see opportunities to further expand our runway in 2016.
Most importantly, in response to the current environment, we lowered our 2016
upstream capital budget to a range of between $200 million and $250 million,
approximately 59% reduction compared to 2015 capital spending levels.
In addition, we anticipate we will fully fund our capital plan with available cash and
cash-flow in 2016 and, at planned spending levels, will see no material change in
our production levels when compared to 2015.
1
Sanchez Energy Corporation Managing Commodity Price Risk
As a further evidence of our financial discipline,
we are actively hedging our production to manage
commodity price risk and protect cash flows.
Sanchez Energy realized the benefits of a strong
hedge portfolio in 2015, and we have extended our
hedge positions into 2016 and 2017. For 2016, we
have hedged all of our expected oil production at
an average price of $64/Bbl and over 90% of our
With $735 million in liquidity and more
than 3,000 Eagle Ford drilling locations,
Sanchez Energy is well-positioned.
expected natural gas production at an average price
of $3.12/MMbtu. As of Dec. 31, 2015 the value of
our hedge positions exceeded $155 million, which
further supports our strong financial position.
Quality asset Base
Despite lower capital spending in 2015, we achieved
record average annual production of approximately
52,500 Boe/d in 2015, an increase of about 72%
over 2014 production levels. Our ability to achieve
record production levels with lower capital spending
is a testament to the efforts of our dedicated
employees and the quality asset base we have
developed through well-executed acquisitions and
organic growth.
As we enter 2016, we have amassed a significant
inventory of over 3,000 Eagle Ford drilling
locations, providing us with high-quality drilling
opportunities for well over 20 years. Our Catarina
asset alone covers a surface area of approximately
106,000 contiguous net acres, which allows
for considerable advantages of scale that are
well-suited to our manufacturing focus and
development strategy.
Although our drilling efforts to date have been
primarily focused on Western Catarina, in 2015
we tested and drilled some of our best wells in the
largely undeveloped South Central area of Catarina.
As we placed little to no value on this area of the
asset at the time of our acquisition,
we now see considerable upside potential
in South Central Catarina.
At Cotulla, we have applied our enhanced
completion practices and manufacturing philosophy
to dramatically improve well economics. As a
result, Cotulla is now showing the best returns in
our portfolio, and we have recently added to our
acreage position in this area.
Best-in-Class Cost struCture
Prudent management of capital and operating costs
are critical factors in today’s business environment,
both in terms of delivering the financial results our
shareholders expect and positioning the Company
for long-term success. While our business plans
may be impacted by commodity price volatility, cost
control is squarely within our sphere of influence.
This acknowledgement lies at the core of our
business strategy.
We believe we have proven, over time and across
the various areas in which we operate, that Sanchez
Energy is an industry leader in asset optimization
and cost control. For example, since acquiring the
Catarina asset in June 2014, we have improved
average well production results by over 40%.
In addition, we are now able to drill wells at Catarina
for approximately $3.5 million, which represents
a cost reduction of approximately 55% when
compared to 2014.
Further, our cost-reduction efforts have been
acknowledged as best in class among our peers,
especially since they have been implemented
without compromising our well design or safety
standards. Approximately half of our realized well-
cost savings have been attained through process
improvements and low-level vertical integration.
As a result, we expect our cost savings to be largely
sustainable, even in a more favorable commodity
price environment.
ComPetitive strengtHs
Strategic Relationship with SPP
In 2015, we realized approximately $430 million
in proceeds from asset sales in two transactions
with Sanchez Production Partners LP (NYSE MKT:
SPP) (“SPP”), a publicly-traded limited partnership
focused on the acquisition, development,
ownership and operation of midstream and other
2
2015 Annual ReportBuilt to PRosPeR rESultS drivEN
$735mm
55%
Liquidity
Position
Decrease
in Well Costs
3,000
Eagle Ford
Locations
72%
Production
Growth
37%
Reduction
in 2015 CAPEX
100%
Oil Production
Hedged in 2016
3
3
Sanchez Energy Corporation energy production assets. The first transaction
involved the sale of escalating working interests
in non-core, producing wellbores and resulted in
aggregate consideration of approximately
$85 million. The second transaction involved the
sale of our Western Catarina midstream gathering
and processing assets and resulted in cash
consideration of approximately $345 million.
We will maintain current production levels
during 2016 even after reducing our 2016
CAPEX budget by 59 % .
Our strategic relationship with SPP enables us to
enhance liquidity at an advantageous cost of capital
to fund our capital plan without having to increase
leverage or dilute our shareholders by issuing equity.
Midstream Capabilities & Advantages
In October 2015, we entered into joint-venture
agreements with Targa Resources Partners LP (“Targa”)
to construct a new, state-of-the-art cryogenic natural
gas processing plant and associated high-pressure
gathering pipelines near our Catarina asset. In addition
to delivering better liquids yields and lower processing
fees, resulting in lower operating costs, higher net-
backs, and greater price realization, the joint ventures
are expected to improve our access to end markets,
including the developing Mexico and global LNG markets.
These midstream joint ventures are a key part of our
strategy aimed at positioning Sanchez Energy to capture
opportunities across the hydrocarbon value chain.
Built to ProsPer
In 2015, we worked to continuously improve Sanchez
Energy and its competitive strengths. As I reflect on our
accomplishments over the past year, I am confident we
have built an organization that will prosper in 2016 and
the years ahead. As we close out 2015, I would like to
thank our dedicated employees, the Sanchez Energy
Board of Directors, our customers, suppliers, service
providers, and you, our shareholders. Our remarkable
results over the past year would not have been
be possible without your continuing support and
confidence in Sanchez Energy.
Antonio R. Sanchez, III
Chief Executive Officer
March 29, 2016
4
2015 Annual ReportBuilt to PRosPeR
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-35372
Sanchez Energy Corporation
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
1000 Main Street, Suite 3000
Houston, Texas
(Address of principal executive offices)
45-3090102
(I.R.S. Employer
Identification No.)
77002
(Zip Code)
(713) 783-8000
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
(Title of Class)
Common Stock, par value $0.01 per share
Rights to purchase Series C Junior Participating Preferred Stock,
par value $0.01 per share
Securities Registered Pursuant to Section 12(g) of the Act: None
(Name of Exchange)
New York Stock Exchange
New York Stock Exchange
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not
be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment
to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a
smaller reporting company)
Smaller Reporting company
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2015: $534,400,409
Number of shares of registrant’s common stock outstanding as of February 26, 2016: 62,579,667.
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders or an amendment to this Form 10-K, which will be filed with
the Securities and Exchange Commission within 120 days of December 31, 2015, are incorporated by reference into Part III of this report for the year ended December 31,
2015.
SANCHEZ ENERGY CORPORATION
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2015
Table of Contents
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Item 13.
Item 14.
Glossary of Selected Oil and Natural Gas Terms
Certain Relationships and Related Transactions and Director Independence
Principal Accountant Fees and Services
Exhibits and Financial Statement Schedules
Item 15.
Signatures
Index to Consolidated Financial Statements
PART IV
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55
57
63
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91
F-1
i
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical
facts, included in this Annual Report on Form 10-K that address activities, events or developments that we expect,
believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on
certain assumptions we made based on management’s experience, perception of historical trends and technical analyses,
current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by
management. When used in this Annual Report on Form 10-K, words such as “will,” “potential,” “believe,” “estimate,”
“intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model,” “strategy,”
“future” or their negatives or the statements that include these words or other words that convey the uncertainty of future
events or outcomes, are intended to identify forward-looking statements, although not all forward-looking statements
contain such identifying words. In particular, statements, express or implied, concerning our future operating results and
returns or our ability to replace or increase reserves, increase production, or generate income or cash flows are
forward-looking statements. Forward-looking statements are not guarantees of performance. Such statements are subject
to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the
expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, no
assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at
all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the
expectations reflected in the forward-looking statements include, among others:
•
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our ability to successfully execute our business and financial strategies;
our ability to utilize the services, personnel and other assets of Sanchez Oil & Gas Corporation (“SOG”)
pursuant to existing services agreements;
our ability to replace the reserves we produce through drilling and property acquisitions;
the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids
(“NGLs”), natural gas and related commodities;
the realized benefits of the acreage acquired in our various acquisitions and other assets and liabilities
assumed in connection therewith;
the realized benefits of our joint ventures, including with respect to our joint ventures with Targa Resources
Partners LP (“Targa”);
the realized benefits of our transactions with Sanchez Production Partners LP (“SPP”), including with
respect to the Palmetto escalating working interest sale and divestiture of Western Catarina midstream
assets referred to herein;
the extent to which our drilling plans are successful in economically developing our acreage in, and to
produce reserves and achieve anticipated production levels from, our existing and future projects;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and
may therefore be imprecise;
the extent to which we can optimize reserve recovery and economically develop our plays utilizing
horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;
our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;
1
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competition in the oil and natural gas exploration and production industry for employees and other
personnel, equipment, materials and services and, related thereto, the availability and cost of employees
and other personnel, equipment, materials and services;
our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at
all, and to otherwise satisfy our capital expenditure requirements;
the availability, proximity and capacity of, and costs associated with, gathering, processing, compression
and transportation facilities;
our ability to compete with other companies in the oil and natural gas industry;
the impact of, and changes in, government policies, laws and regulations, including tax laws and
regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic
fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on
drilling and completion operations and laws and regulations with respect to derivatives and hedging
activities;
developments in oil-producing and natural gas-producing countries, the actions of the Organization of
Petroleum Exporting Countries (“OPEC”) and other factors affecting the supply of oil and natural gas;
our ability to effectively integrate acquired crude oil and natural gas properties into our operations, fully
identify existing and potential problems with respect to such properties and accurately estimate reserves,
production and costs with respect to such properties;
the extent to which our crude oil and natural gas properties operated by others are operated successfully and
economically;
the use of competing energy sources and the development of alternative energy sources;
unexpected results of litigation filed against us;
the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our
insurance coverage; and
the other factors described under “Item 1A. Risk Factors” in this Annual Report on Form 10-K and any
updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on
Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by our forward-looking statements
may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the
extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of our
forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made,
and we undertake 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.
2
Item 1. Business
Overview
PART I
Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,”
“we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and
production company focused on the exploration, acquisition and development of unconventional oil and natural gas
resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and, to a lesser
extent, the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana. We have accumulated approximately
200,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and
approximately 62,000 net leasehold acres in what we believe to be the core of the TMS. We are currently focused on the
horizontal development of significant resource potential from the Eagle Ford Shale, with plans to invest approximately
100% of our total 2016 drilling and completion capital budget in this area. We are continuously evaluating opportunities
to grow both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will
depend on both the opportunities and the financing alternatives available to us at the time we consider such
opportunities. We have included definitions of some of the oil and natural gas terms used in this Annual Report on
Form 10-K in the “Glossary of Selected Oil and Natural Gas Terms.”
Listed below is a table of our significant transactions since January 1, 2013:
Transaction
Western Catarina Midstream Divestiture
Palmetto Disposition
Catarina Acquisition
Wycross Acquisition
TMS transaction
Five Mile Creek Acquisition
Cotulla Acquisition
Transaction
Date
Transaction
Effective
Date
Core Area
Net
Acreage
Acquired
Net
Acreage
Remaining
at 12/31/15
N/A
10/14/2015 10/14/2015 Catarina, Eagle Ford
1/1/2015 Palmetto, Eagle Ford
N/A
1/1/2014 Catarina, Eagle Ford 106,100
3,600
7/1/2013 Wycross, Eagle Ford
69,000
8/16/2013
10,300
7/1/2013 Marquis, Eagle Ford
44,500
3/1/2013 Cotulla, Eagle Ford
3/31/2015
6/30/2014
10/4/2013
8/16/2013
7/1/2013
5/31/2013
TMS
N/A $
N/A $
106,100 $
3,600 $
62,000 $
6,300 $
31,200 $
Purchase /
Disposition
Price
(millions)
346
83
557
230
78
29
281
On October 14, 2015, the Company completed the Western Catarina Midstream Divestiture (as defined below
in Note 3, “Acquisitions and Divestitures”) for an adjusted purchase price of $345.8 million in cash. In connection with
the closing of the Western Catarina Midstream Divestiture, the Company entered into a Firm Gathering and Processing
Agreement (the “Gathering Agreement”) on October 14, 2015 for an initial term of 15 years under which production
from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by
Catarina Midstream, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN
Catarina, LLC will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of
crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments.
On March 31, 2015, we completed the Palmetto Disposition (as defined below in Note 3, “Acquisitions and
Divestitures”) for an adjusted purchase price of approximately $83.4 million. The effective date of the transaction was
January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and,
upon January 1 of each subsequent year after the closing, the working interest of the purchaser, a wholly owned
subsidiary of SPP, will automatically increase in incremental amounts according to the purchase agreement until January
1, 2019, at which point the purchaser will own a 47.5% working interest, and we will own a 2.5% working interest in
each of the wellbores.
On June 30, 2014, we completed our acquisition of 106,000 net contiguous acres in Dimmit, LaSalle and Webb
Counties, Texas (the “Catarina Acquisition”) in the Eagle Ford Shale with an effective date of January 1, 2014. All
proved reserves in the Catarina area are covered under lease acreage that is held by production, which acreage amounted
to approximately 29,000 acres. Under the lease we have a 100% working interest and 75% net revenue interest in the
3
lease acreage over the Eagle Ford Shale formation from the top of the Austin Chalk formation to the base of the Buda
Lime formation. The 77,000 acres of undeveloped acreage that were included in the Catarina Acquisition are subject to a
continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing
on July 1, 2014 and (ii) at least one well in any consecutive 120-day period in order to maintain rights to any future
undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried
over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also
created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and
other lease obligations. Our current capital budget and plans include drilling at least the minimum annual well
requirement necessary to maintain access to such undeveloped acreage.
On October 4, 2013, we completed our acquisition of approximately 3,600 net contiguous acres of leasehold in
McMullen County, Texas (the “Wycross Acquisition”) in the Eagle Ford Shale. The properties acquired in the Wycross
Acquisition are included in our Cotulla area described below.
On August 16, 2013, we completed an asset acquisition of approximately 40,000 net developed and
undeveloped acres in the TMS (the “TMS Transaction”) in Southwest Mississippi and Southeast Louisiana and the
formation of an area of mutual interest (“AMI”) and a 50/50 joint venture with SR Acquisition I, LLC (“SR”), a
subsidiary of our affiliate Sanchez Resources, LLC (“Sanchez Resources”). As of December 31, 2015 the AMI held
rights to approximately 135,000 (95,000 net) acres, of which we owned approximately 62,000 net acres.
In July 2013, we acquired approximately 10,300 net acres in Fayette, Gonzales and Lavaca Counties, Texas (the
“Five Mile Creek Acquisition”). The properties acquired in the Five Mile Creek Acquisition are included in our Marquis
area, and are directly to the northwest of our Prost development project.
On May 31, 2013, we completed our acquisition of 44,461 net acres in Dimmit, Frio, LaSalle and Zavala
Counties, Texas (the “Cotulla Acquisition”). We combined our Cotulla assets with our previous Maverick area to form
one operating area now known as our Cotulla area. As noted above, the Cotulla area also includes the properties acquired
in the Wycross Acquisition.
Our 2016 capital budget of $200 - $250 million is allocated approximately 89% to the drilling of 52 net wells
and to the completing of 55 net wells with the remainder allocated to facilities, leasing, and seismic activities.
For 2016, our operating plans will largely focus on continued improvement to our manufacturing efficiency
with the goal of steady improvement in our capital efficiency in order to preserve liquidity and financial flexibility. Our
2016 capital budget will be focused on the development of our approximately 200,000 net acres in the Eagle Ford Shale
where we plan on investing approximately 100% of the allocated drilling and completion budget.
The following table presents summary data for our Eagle Ford and TMS project areas as of December 31, 2015
as well as our capital expenditure budget for the 2016 fiscal year:
Average
Working
Interest (1)
Net
Acreage
106,051
50,984
8,485
34,173
199,693
61,933
261,626
Operator
100% Sanchez Energy
88% Sanchez Energy
48% Marathon
100% Sanchez Energy
93%
65% Sanchez Oil and Gas
84%
Identified
Drilling
Gross Net
Locations (2) Net
Wells
Spud
35
15
2
-
52
-
52
1,486
891
153
387
2,917
196
3,113
1,486
974
317
387
3,164
300
3,464
2016 Capital Expenditure Budget
Drilling &
Completion
("D&C")
Capital
% of
Operating
Net Wells
Completed
(in millions)
% of
D&C
Capital
70%
23%
7%
0%
100%
0%
100%
Capital
62%
20%
7%
0%
89%
0%
89%
36 $130 - $150
$40 - $50
15
$10 - $20
4
$0
-
55 $180 - $220
-
$0
55 $180 - $220
$20 - $30
$200 - $250
11%
100%
Catarina
Cotulla
Palmetto
Marquis
Total Eagle Ford
TMS
Total
Facilities, Leasing and Seismic
Total Capital Budget
(1) Average working interests reflect the Company’s average working interests in the leases it holds.
4
(2) Using approximately 40 acre well-spacing for our Cotulla and Palmetto areas, approximately 60 acre well-spacing
for our Marquis area, and approximately 75 acre well-spacing for our Catarina area plus up to 650 additional upper
Eagle Ford Catarina locations, and assuming 80% of the acreage is drillable for Cotulla, Marquis and Catarina, and
90% of the acreage is drillable for Palmetto, we believe that there could be over 3,100 potential gross (2,900 net)
locations for potential future drilling in the Eagle Ford. Using approximately 250 acre well-spacing for our TMS
area and assuming 80% of the acreage is drillable, we believe that there are up to 300 gross (200 net) locations for
potential future drilling. In total, we believe that there are over 3,400 potential gross (3,100 net) Eagle Ford and
TMS locations for future drilling.
Our Business Strategies
Our primary business objective is to increase reserves, production and cash flows at an attractive return on
invested capital. Our business strategy is currently focused on exploiting long-life, unconventional oil, condensate, NGL
and natural gas reserves from the Eagle Ford Shale and the TMS, as well as a diversification into the midstream elements
of the market that adds value to our operations. Key elements of our business strategy include:
• Efficiently develop our Eagle Ford Shale leasehold positions. We intend to efficiently drill and develop
our acreage position to maximize the value of our resource potential. At December 31, 2015, approximately
49% of our proved reserves were proved undeveloped. As of December 31, 2015, we were producing from
621 wells and have identified over 2,900 net locations for potential future drilling in our Eagle Ford Shale
area that will be our primary targets in the near term. In 2016, we plan to invest between $180 and
$220 million on development drilling and completion in the Eagle Ford Shale to spud 52 net wells and
complete approximately 55 net wells. This represents approximately 100% of our 2016 drilling and
completion budget and 89% of our total 2016 capital budget.
• Enhance returns by focusing on operational and cost efficiencies. We are focused on continuous
improvement of our operating measures and have significant experience in successfully converting
early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and
concentration of our acreage within our core project areas provide us with the opportunity to capture
economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing
centralized production and fluid handling facilities and reducing the time and cost of rig mobilization.
• Add value through owning midstream functions. The Company’s Marketing & Midstream Group (the
“Marketing and Midstream Group”) was formed in 2014 to more effectively manage our expanding
midstream business segment. Our goal is to participate in the midstream function in order to capture more
of the hydrocarbon value chain. The Marketing and Midstream Group focuses on projects that serve our
production and add optionality to end markets which improves our netback price. As a secondary focus, the
Marketing and Midstream Group also evaluates midstream projects that are accretive to the Company and
add scale and diversification to our midstream portfolio.
• Adopt and employ leading drilling and completion techniques. We are focused on enhancing our drilling
and completion techniques to maximize recovery of reserves. Industry techniques with respect to drilling
and completion have significantly evolved over the last several years, resulting in increased initial
production rates and recoverable hydrocarbons per well through the implementation of longer laterals and
more tightly spaced fracture stimulation stages. We continuously evaluate industry drilling results and
monitor the results of other operators to improve our operating practices, and we expect our drilling and
completion techniques will continue to evolve.
5
• Leverage our relationship with our affiliates to expand unconventional oil, condensate, NGL and
natural gas assets. SOG, headquartered in Houston, Texas, is a private full service oil and natural gas
company engaged in the exploration and development of oil and natural gas primarily in the South Texas
and onshore Gulf Coast areas on behalf of its affiliates. The Company refers to SOG, Sanchez Energy
Partners I, LP, and their affiliates (but excluding the Company), collectively, as the “Sanchez Group.”
Various members of the Sanchez Group have drilled or participated in over 1,200 wells, directly and
through joint ventures, and have invested substantial amounts of capital in the oil and natural gas industry
since 1972. During this period, they have carefully cultivated relationships with mineral and surface rights
owners in and around our Eagle Ford and TMS areas and compiled an extensive technological database
which we believe gives us a competitive advantage in acquiring additional leasehold positions in these
areas. We have unrestricted access to the proprietary portions of the technological database related to our
properties and SOG is otherwise required to interpret and use the database for our benefit. We plan to
leverage our affiliates’ expertise, industry relationships and size to opportunistically expand reserves and
our leasehold positions in the Eagle Ford Shale and other onshore unconventional oil, condensate, NGL and
natural gas resources.
• Pursue strategic acquisitions to grow our leasehold position in the Eagle Ford Shale and seek entry into
new basins. We believe that we will be able to identify and acquire additional acreage and producing
assets in the Eagle Ford Shale at attractive valuations by leveraging our longstanding relationships in and
knowledge of South Texas. We also plan to selectively target additional domestic basins that would allow
us to employ our strategies on attractive acreage positions that we believe are similar to our Eagle Ford
Shale acreage. Our 2013 TMS Transaction was consistent with this strategy and gave us approximately
40,000 net acres, currently 62,000 net acres, within what we believe to be the core of the TMS.
• Maintain substantial financial liquidity and flexibility. As of December 31, 2015, we had approximately
$435 million of cash and cash equivalents and a $500 million unused, available borrowing base (with a
$300 million aggregate elected commitment amount) under our Fifth Amendment to the Second Amended
and Restated Credit Agreement (defined in Note 5, “Long-Term Debt”). We believe that this strong
liquidity position combined with our cash flow from operations will allow us to maintain our total
production of hydrocarbons at the approximate levels we reported for 2015. We plan to continuously
evaluate our level of operating activity in light of both actual commodity prices and changes we are able to
make to our costs of operations and make further adjustments to our capital spending program as
appropriate. In addition, we expect to continue to regularly review acquisition opportunities from third
parties or other members of the Sanchez Group. The Company does not expect that any potential future
changes to our borrowing base would impact our aggregate elected commitment amount. Furthermore, we
have entered into and intend to continue executing hedging transactions for a significant portion of our
expected production to achieve more predictable cash flow and to reduce our exposure to adverse
fluctuations in oil and natural gas prices.
Our Competitive Strengths
We believe the following competitive strengths will allow us to successfully execute our business strategies:
• Geographically concentrated leasehold position in leading North American unconventional oil resource
trends. We have assembled a current leasehold position of approximately 200,000 net acres in the Eagle
Ford Shale, which we believe to be one of the highest rates of return unconventional oil and natural gas
formations in North America. In addition to further leveraging our base of technical expertise in our project
areas, our geographically concentrated acreage position allows us to establish economies of scale with
respect to drilling, production, operating and administrative costs in addition to further leveraging our base
of technical expertise in our project areas. We believe that our recent well results and offset operator
activity in and around our project areas have significantly de-risked our acreage position such that there are
low geologic risks and ample repeatable drilling opportunities across our core operating areas. In addition
to our Eagle Ford Shale acreage, we have approximately 62,000 net acres in what we believe to be the core
of the TMS. Well results in the TMS remain strong although development is currently challenged due to
high well costs and depressed commodity prices. We believe that the TMS play has significant
development potential and still has significant upside as changes in technology, commodity prices, and
service prices occur.
6
•
Proven low cost operator. We are recognized as one of the lowest cost operators in the Eagle Ford. We
utilize a combination of initiatives that have improved the efficiency of our operations and reduced the cost
of sourcing goods and services. The Company has implemented systems and processes that provide
complete transparency for our well program across our organization thereby eliminating drag and waste on
repetitive tasks. We have segmented and optimized each step in drilling and completing a well. Our supply
chain management team takes a rigorous and methodical approach to reducing the total delivered costs of
purchased good and services by examining costs on its most granular level. Goods and services are
commonly sourced directly from suppliers, eliminating the middleman and markups. Additionally, we
constantly review the value chain for opportunities to internally provide services in order to further reduce
cost and eliminate inflation
• Demonstrated ability to drive oil production and reserves growth. Our average production for the fourth
quarter of 2015 was 58,115 boe/d, substantially all of which was from the Eagle Ford Shale. This compares
to approximately 52,844 boe/d in the third quarter of 2015 and 43,893 boe/d during the fourth quarter of
2014. Our total proved reserves at December 31, 2015 was 127.6 mboe, a decrease of approximately 5%
over the same period a year ago, primarily due to the negative impact of SEC WTI and Henry Hub price
decreases offset by an increase in drilling and development.
• Large oil-weighted multi-year drilling inventory. We have an inventory of over 2,900 net locations for
potential future drilling on our acreage position in the oil and condensate, or black oil and volatile oil,
windows of the Eagle Ford Shale based on spacing varying from 75 acres to 40 acres. In 2016, we plan to
spud approximately 52 net wells and complete approximately 55 net wells on our existing Eagle Ford Shale
acreage. We have an inventory of up to approximately 200 net oil weighted locations in our TMS area. Our
knowledge about the basin’s potential will be enhanced by continued delineation and development drilling
in the TMS by us and other operators.
• Experienced management and strong technical team. Our team is comprised of individuals with a long
history in the oil and natural gas business, and a number of our key executives have prior experience as
members of public company management teams. Furthermore, members of the Sanchez Group have a
40-plus year operating history in the basins in which we operate, providing us with extensive knowledge of
the basins and the ability to leverage longstanding relationships with mineral owners. Through SOG, we
have access to an experienced staff of oil and natural gas professionals including geophysicists, geologists,
drilling and completion engineers, production and reservoir engineers and technical support staff. This
technical team is large enough to support our growth into a significantly larger company relative to our
current size. SOG’s technical team has significant experience and expertise in applying the most
sophisticated technologies used in conventional and unconventional resource style plays including 3-D
seismic interpretation capabilities, horizontal drilling, comprehensive multi-stage hydraulic fracture
stimulation programs and other exploration, production and processing technologies. We believe this
technical expertise is integral to successful exploitation of our assets, including defining new core
producing areas in emerging plays.
Core Properties
Eagle Ford Shale
We and our predecessor entities have a long history in the Eagle Ford Shale, where we have assembled
approximately 200,000 net leasehold acres with an average working interest of approximately 93%. Using approximately
40 acre well-spacing for our Cotulla and Palmetto areas, approximately 60 acre well-spacing for our Marquis area, and
approximately 75 acre well-spacing for our Catarina area plus up to 650 additional upper Eagle Ford Catarina locations,
and assuming 80% of the acreage is drillable for Cotulla, Marquis and Catarina, and 90% of the acreage is drillable for
Palmetto, we believe that there could be over 3,100 potential gross (2,900 net) locations for potential future drilling.
Consistent with other operators in this area, we perform multi-stage hydraulic fracturing up to 30 stages on each well
depending upon the length of the lateral section. For the year 2016, we plan to invest substantially all of our capital
budget in the Eagle Ford Shale.
7
In our Catarina area, we have approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas
with a 100% working interest. We anticipate drilling, completion and facilities costs on our acreage to be between $3.3
million and $3.6 million per well based on our current estimates and historical well costs. Current Estimated Ultimate
Recovery (“EUR”) per well in Catarina is expected to range between 400 mboe and 1,200 mboe. We have identified
between 1,300 and 1,650 gross and net locations for potential future drilling on our Catarina acreage. For the year 2016,
we plan to spend $130 - $150 million to spud 35 and complete 36 net wells in our Catarina area.
In our Marquis area, we have approximately 59,500 net acres, the majority of which are in southwest Fayette
and northeast Lavaca Counties, Texas with a 100% working interest. We believe that our Marquis acreage lies in the
volatile oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between
$4.0 million and $5.0 million per well based on our current estimates and historical well costs. Current EUR per well in
Marquis is expected to range between 275 mboe and 375 mboe. We have identified up to 387 gross and net locations
based on 60 acre well-spacing for potential future drilling on our Marquis acreage. For the year 2016, we do not have
any capital budgeted to spend on drilling and completions in our Marquis area.
In our Cotulla area, we have approximately 35,000 net acres in Dimmit, Frio, LaSalle, Zavala, and McMullen
Counties, Texas with an average working interest of approximately 85%. We believe that our Cotulla acreage lies in the
black oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $3.0 million
and $4.0 million per well based on our current estimates and historical well costs. Current EUR per well in Cotulla is
expected to range between 300 mboe and 400 mboe. We have identified up to 995 gross (910 net) locations based on 40
acre well-spacing for potential future drilling on our Cotulla area. For the year 2016, we plan to spend $40 - $50 million
to spud three net wells and complete 15 net wells in our Cotulla area.
In our Palmetto area, we have approximately 8,500 net acres in Gonzales County, Texas with an average
working interest of approximately 48%. We believe that our Palmetto acreage lies in the volatile oil window where we
anticipate drilling, completion and facilities costs on our acreage to be between $5.5 and $6.0 million per well based on
our current estimates and historical well costs. Current EUR per well in Palmetto is expected to range between 500 mboe
and 600 mboe. We have identified up to 317 gross (153 net) locations based on 40 acre well-spacing for potential future
drilling in our Palmetto area. For the year 2016, we plan to spend $10 - $20 million to spud two net wells and complete
four net wells in our Palmetto area.
Tuscaloosa Marine Shale
In August 2013, we acquired approximately 40,000 net undeveloped acres in what we believe to be the core of
the TMS for cash and shares of our common stock. In connection with the TMS Transaction, we established an AMI in
the TMS with SR, which transaction included a carry on drilling costs for up to 6 gross (3 net) wells. As part of the
transaction, we acquired all of the working interests in the AMI owned at closing from three sellers (two third parties and
one related party of the Company, SR), resulting in our owning an undivided 50% working interest across the AMI
through the TMS formation. As of December 31, 2015, the AMI held rights to approximately 135,000 (95,000 net) acres,
of which we owned approximately 62,000 net acres.
Total consideration for the transactions consisted of approximately $70 million in cash and the issuance of
342,760 common shares of the Company, valued at approximately $7.5 million. The total cash consideration provided to
SR, an affiliate of the Company, was $14.4 million, before consideration of any well carries. The acquisitions were
accounted for as the purchase of assets at cost at the acquisition date. We also committed, as a part of the total
consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the
AMI (the “Initial Well Carry”) with an option to drill an additional 6 gross (3 net) TMS wells (“Additional Wells”)
within the AMI. In August 2015, after completing the Initial Well Carry, the Company signed an agreement with SR
whereby the Company paid SR approximately $8 million in lieu of drilling the remaining two Additional Wells (the
“Buyout Agreement”). The Buyout Agreement stipulates that SN has earned full rights to all acreage stated in the TMS
Transaction and effectively terminates any future well carry commitments.
8
Well results in the TMS remain strong although development is currently challenged due to high well costs and
depressed commodity prices. We believe that the TMS play has significant development potential and still has
significant upside as changes in technology, commodity prices, and service prices occur. The average remaining lease
term on the acreage is over 3 years, giving us ample time to allow other industry participants to further de-risk the play.
Oil and Natural Gas Reserves and Production
Internal Controls
Our estimated reserves at December 31, 2015 were prepared by Ryder Scott Company, L.P. (“Ryder Scott”),
our independent reserve engineers. We expect to continue to have our reserve estimates prepared semi-annually by our
independent third-party reserve engineers. Our internal professional staff works closely with Ryder Scott to ensure the
integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve
information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we
provide Ryder Scott other pertinent data, such as seismic information, 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.
Technology Used to Establish Reserves
Under the rules of the Securities and Exchange Commission (the “SEC”), proved reserves are those quantities
of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to
be economically producible from a given date forward from known reservoirs, and under existing economic conditions,
operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that
the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be
established using techniques that have been proven effective by actual production from projects in the same reservoir or
an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable
technology is a grouping of one or more technologies (including computational methods) that has been field tested and
has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being
evaluated or in an analogous formation.
To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed
technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and
economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs,
core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves
attributable to producing wells with sufficient production history were estimated using appropriate decline curves or
other performance relationships. Reserves attributable to producing wells with limited production history and for
undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic
data to assess the reservoir continuity. These wells were considered to be analogous based on production performance
from the same formation and completion using similar techniques.
Qualifications of Responsible Technical Persons
Internal SOG Engineers. Vinodh Kumar is the technical person primarily responsible for overseeing the
preparation of our reserve estimates. Mr. Kumar has over 40 years of industry experience with positions of increasing
responsibility in engineering and evaluations with companies such as Hilcorp Energy Company, El Paso Exploration &
Production Company, KCS Energy, Inc. and Koch Industries, Inc. He holds a Masters of Science degree in Petroleum
Engineering from the University of Calgary and a Masters of Business Administration from Wichita State University.
Mr. Kumar is a Registered Professional Engineer in the State of Texas.
Independent Reserve Engineers. Ryder Scott is an independent oil and natural gas consulting firm. No director,
officer or key employee of Ryder Scott has any financial ownership in any member of the Sanchez Group or us. Ryder
Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results
obtained and reported, and Ryder Scott has not performed other work for SOG, Sanchez Energy Partners I, LP (“SEP I”)
9
or us that would affect its objectivity. The engineering information presented in Ryder Scott’s report was overseen by
Don P. Griffin, P.E. Mr. Griffin is an experienced reservoir engineer having been a practicing petroleum engineer since
1976. He has more than 30 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science
degree in Electrical Engineering from Texas Tech University. Mr. Griffin is a Registered Professional Engineer in the
State of Texas.
Estimated Proved Reserves
The following table presents the estimated net proved oil and natural gas reserves attributable to our properties
and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of
December 31, 2015, based on a reserve report prepared by Ryder Scott, our independent reserve engineers. The
standardized measure amounts shown in the table are not intended to represent the current market value of our estimated
oil and natural gas reserves.
10
As of December 31, 2015
Total
Estimated
Proved
Natural Gas Reserves
Natural Gas
Liquids
(mmbo) (mmbbl)
Oil
Reserve Data (1):
Estimated proved reserves by project area:
Eagle Ford
Catarina
Cotulla
Marquis
Palmetto
Total Eagle Ford
TMS
Total
Standardized Measure (in millions) (1)(3)
Estimated proved developed reserves by project area:
Eagle Ford
Catarina
Cotulla
Marquis
Palmetto
Total Eagle Ford
TMS
Total
Estimated proved undeveloped reserves by project area:
Eagle Ford
Catarina
Cotulla
Marquis
Palmetto
Total Eagle Ford
TMS
Total
17.3
17.8
3.4
13.1
51.6
0.2
51.8
11.0
6.6
3.1
0.8
21.5
0.2
21.7
6.3
11.2
0.3
12.3
30.1
—
30.1
32.4
1.4
0.5
2.5
36.8
—
36.8
19.1
1.0
0.5
0.2
20.8
—
20.8
13.3
0.4
—
2.3
16.0
—
16.0
PV-10
(bcf)
(mmboe)(2) (in millions)
210.0
8.2
2.0
14.2
234.4
—
234.4
123.9
5.8
2.0
1.3
133.0
—
133.0
86.1
2.4
0.1
13.0
101.6
—
101.6
84.8 $
20.5
4.2
18.0
127.5
0.2
127.7 $
$
294.7
199.7
51.4
44.0
589.8
3.7
593.5
593.5
50.8 $
8.5
3.9
1.2
64.4
0.2
64.6 $
275.5
115.2
51.8
19.4
461.9
3.6
465.5
33.9 $
12.0
0.3
16.7
62.9
—
62.9 $
19.2
84.5
(0.4)
24.7
128.0
—
128.0
(1) Our estimated net proved reserves and related standardized measure were determined using index prices for oil and
natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our
properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were
$50.28/bo for oil, $19.90/bbl for NGLs and $2.58/mmbtu for natural gas at December 31, 2015. These prices were
adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and
other factors affecting the price realized at the wellhead. For the year ended December 31, 2015, the average
realized prices for oil, NGLs and natural gas were $42.98 per bo, $11.99 per bbl and $2.63 per mcf, respectively. For
a description of our commodity derivative contracts, please read “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Results of Operations—Costs and Operating Expenses—
Commodity Derivative Transactions” and “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations—Critical Accounting Policies and Estimates—Derivative Instruments.”
11
(2) One boe is equal to six mcf of natural gas or one bo of oil or NGLs based on a rough energy equivalency. This is a
physical correlation and does not reflect a value or price relationship between the commodities.
(3) Standardized measure is calculated in accordance with Accounting Standards Codification (“ASC”), Topic 932,
Extractive Activities—Oil and Gas. For further information regarding the calculation of the standardized measure,
see “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities
(Unaudited)” included in “Item 8. Financial Statements and Supplementary Data.”
The data in the table above represents estimates only. Oil, NGLs and natural gas reserve engineering is
inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be
measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and
geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and
natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates, please read
“Item 1A. Risk Factors—Our estimated reserves and future production rates are based on many assumptions that may
prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially
affect the quantities and present value of our estimated reserves.”
Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs
assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the
current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate
standardized measure, which is required by Financial Accounting Standard Board (“FASB”) pronouncements, is not
necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially
affected by assumptions as to timing of future production, which may prove to be inaccurate.
Development of Proved Undeveloped Reserves
None of our proved undeveloped reserves (“PUD”) at December 31, 2015 are scheduled to be developed on a
date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our
drilling and development programs were substantially funded from capital contributions, cash flow from operations and
the issuance of debt and equity securities. Based on our current expectations of our cash flows and drilling and
development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling
of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from
our cash on hand combined with cash flow from operations and utilization of available borrowing capacity under our
credit facility.
At a pace of approximately 30 wells per rig per year, our current PUD drilling locations will all be developed
within the next five years by running an average gross rig count of two rigs. As of December 31, 2015, we are running
two active rigs and have an approved annual budget that allows for approximately two rigs to be run through 2016. For a
more detailed discussion of our liquidity position, please read “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital Resources.”
12
As of December 31, 2015, we identified 218 gross (159 net) PUD drilling locations which we anticipate drilling
within the next five years. The table below details the activity in our PUD locations from December 31, 2014 to
December 31, 2015:
PUDs as of December 31, 2014
Revisions of previous estimates
Revisions due to price change
Technical revisions
Extensions and discoveries
Purchases
Divestitures
Conversion to proved developed reserves during the year
PUDs as of December 31, 2015
Net Natural
Net Oil Gas Liquids
(mbbl)
37,074
(mbbl)
16,730
Net
Natural
Gas
Net
Volume
(mmcf) (mboe)
70,322
99,110
(11,937)
1,431
8,796
—
—
(5,316)
30,048
(3,538)
3,397
5,440
—
—
(6,034)
15,995
(19,968)
23,302
35,226
—
—
(36,106)
101,564
(18,802)
8,712
20,107
—
—
(17,368)
62,971
We note that our proved reserve volumes contained in our reserve report include PUD locations that have a
negative present value when discounted at 10%. There are a total of 93 such locations representing total net volumes of
29.3 mmboe in our reserve report as of December 31, 2015. Despite the negative present value associated with these
locations, management considers these locations economical on an undiscounted basis, and as such, is committed to
developing these locations within the next five years. Excluding acquisitions, we expect to make capital expenditures
related to drilling and completion of wells of approximately $220 to $230 million during the year ending December 31,
2016. We plan to spend approximately 50% to 52% of these capital expenditures on development of PUDs in 2016.
Technical revisions of PUD estimates are a result of changes in forecasted performance. There are net positive changes
on our PUD forecasts driven by better performance on our Catarina asset. As a result of price change, approximately 89
PUD locations were removed. The total PUD volumes impacted by price changes are 18,802 mboe as a result of the
locations that were removed from our Catarina, Marquis, and Wycross assets.
For more information about our historical costs associated with the development of proved undeveloped
reserves, please read “Supplementary Information on Oil and Natural Gas Exploration, Development and Production
Activities (Unaudited)” included in “Item 8. Financial Statements and Supplementary Data.”
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 financial measure in accordance with accounting principles generally accepted in the United States of
America (“U.S. GAAP”). PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the
Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that
the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows
attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a
useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors
may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We
use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10,
however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not
purport to present the fair value of our oil and natural gas reserves.
13
The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2015 for
our proved reserves (in millions):
PV-10
Present value of future income taxes discounted at 10%
Standardized Measure (1)
Proved
Reserves
$
$
593.5
—
593.5
(1) Standardized measure is calculated in accordance with ASC Topic 932, Extractive Activities—Oil and Gas. For
further information regarding the calculation of the standardized measure, see “Supplementary Information on Oil
and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in “Item 8. Financial
Statements and Supplementary Data.”
14
Production, Revenues and Price History
The following table sets forth information regarding combined net production of oil, NGLs, and natural gas and
certain price and cost information attributable to our properties for each of the periods presented:
Production:
Oil - mbo
Catarina
Marquis
Cotulla
Palmetto
Other
Total
Natural gas liquids - mbbl
Catarina
Marquis
Cotulla
Palmetto
Other
Total
Natural gas - mmcf
Catarina
Marquis
Cotulla
Palmetto
Other
Total
Net production volumes:
Total oil equivalent (mboe)
Average daily production (boe/d)
Average Sales Price (1):
Oil ($ per bo)
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)
Oil equivalent ($ per boe)
Average unit costs per boe:
Oil and natural gas production expenses
Production and ad valorem taxes
General and administrative (2)(3)
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
(1) Excludes the impact of derivative instruments.
Year Ended December 31,
2015
2014
2013
3,209.9
1,447.8
1,832.4
606.0
68.6
7,164.7
5,065.6
217.6
332.2
138.7
—
5,754.1
846.7
1,910.4
1,868.1
1,422.6
31.8
6,079.6
1,579.5
251.2
485.7
273.7
—
2,590.1
33,775.4
901.4
2,117.2
773.5
26.6
37,594.1
9,244.2
974.4
3,066.6
1,542.3
—
14,827.5
—
724.5
1,098.3
1,085.6
0.2
2,908.6
—
63.8
204.5
186.7
—
455.0
—
383.7
1,402.1
1,234.4
28.3
3,048.5
19,184.4
52,560.1
11,141.0
30,523.2
3,871.6
10,607.1
$
$
$
$
$
$
$
$
$
42.98 $
11.99 $
2.63 $
24.80 $
88.64 $
25.86 $
4.06 $
59.79 $
8.16 $
1.40 $
2.89 $
17.96 $
71.15 $
8.40 $
3.39 $
4.40 $
30.35 $
19.19 $
99.82
28.60
3.64
81.21
9.21
4.47
6.73
34.82
—
(2) For the years ended December 31, 2015, 2014 and 2013, general and administrative excludes non-cash stock-based
compensation expense of approximately $14.8 million ($0.77 per boe), $12.8 million ($1.15 per boe), and $17.8
million ($4.58 per boe), respectively.
(3) For the years ended December 31, 2015, 2014 and 2013, general and administrative excludes acquisition and
divestiture costs included in general and administrative expense of $3.8 million ($0.20 per boe), $1.8 million ($0.16
per boe), and $4.1 million ($1.07 per boe), respectively.
15
Drilling Activities
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. At
December 31, 2015, 15 gross wells were in various stages of completion.
Development wells:
Productive
Dry
Exploratory wells:
Productive
Dry
Total wells:
Productive
Dry
Year Ended December 31,
2015
2014
2013
Gross Net
Gross Net Gross Net
128.0
—
108.0
—
115.0
—
82.0
—
84.0
—
59.5
—
8.0
—
8.0
—
6.0
—
5.5
—
4.0
—
3.1
—
136.0
—
116.0
—
121.0
—
87.5
—
88.0
—
62.6
—
The following table sets forth information at December 31, 2015 relating to the productive wells in which we
owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to
production facilities. 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.
Operated by us
Non-operated
Total
Developed and Undeveloped Acreage
210.0
115.0
325.0
172.0
39.6
211.6
295.0
1.0
296.0
292.7
0.3
293.0
Oil
Gross Net
Natural Gas
Gross Net
The following table sets forth information as of December 31, 2015 relating to our leasehold acreage. Acreage
related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31,
2015, 71% of our acreage was held by production.
Catarina
Cotulla
Marquis
Palmetto
Total Eagle Ford
TMS
Total
Developed Acreage
Gross Net
Undeveloped Acreage
Gross Net
22,125
5,840
4,140
3,160
35,265
1,000
36,265
22,125
5,144
4,140
1,525
32,934
652
33,586
83,926
52,040
30,033
14,424
180,423
94,057
274,480
83,926
45,840
30,033
6,960
166,759
61,281
228,040
As of December 31, 2015, approximately 71% of our acreage was held by production. We have leases that were
not held by production representing 15,383 net acres (11,137 of which were in the Eagle Ford Shale) expiring in 2016,
15,522 net acres (12,249 of which were in the Eagle Ford Shale) expiring in 2017, and 44,355 net acres (9,192 of which
16
were in the Eagle Ford Shale) expiring in 2018 and beyond. We anticipate that our current and future drilling plans along
with selected lease extensions will address the majority of our leases expiring in the Eagle Ford Shale in 2016 and
beyond. In addition to these lease expirations, we also have a continuous development obligation in our Catarina area
that requires us to drill, but not complete, (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least
one well in any consecutive 120 day period in order to maintain rights to any future undeveloped acreage.
Delivery Commitments
We have made commitments to certain purchasers to deliver a portion of our natural gas production from our
Cotulla and Catarina areas.
The total amount contracted to be delivered in our Cotulla area is approximately 18 bcf of natural gas through
2021. The price for these deliveries is set at the time of delivery of the product. We have more production capacity than
the amounts committed and none of the commitments in any given year are material.
In our Catarina area, we have contracts with three processing facilities to deliver a portion of our natural gas
production. The total amount contracted to be delivered in our Catarina area is approximately 356 bcf of natural gas with
contracts expiring in 2016, 2020 and 2021. During 2015, we recorded expenses related to deficiencies on delivery
commitments. These amounts were recorded to oil and natural gas production expenses in our consolidated statement of
operations and were not considered material to the financial statement line item or to the consolidated financial
statements as a whole. We do not expect to have additional expenses in 2016 related to deficiencies on our delivery
commitments.
Also in our Catarina area, we have one contract to deliver a portion of our oil production. The total amount
contracted to be delivered in our Catarina area is approximately 19 MMBbls of oil expiring in 2020. We do not expect to
have additional expenses in 2016 related to deficiencies on our delivery commitments.
Operations
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 well drilled on the lease premises. The lessor royalties
and other leasehold burdens on our Eagle Ford properties range from 20.9% to 30.5%, resulting in a net revenue interest
to us ranging from 69.5% to 79.1%.
Marketing and Major Customers
For the year ended December 31, 2015, purchases by two of our customers accounted for 38% and 14%,
respectively, of our total revenues. The two customers purchased oil, NGLs and natural gas production from us pursuant
to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month
basis until either party gives 30-day advance written notice of non-renewal.
Since the oil, NGLs and natural gas that we sell are commodities for which there are a large number of potential
buyers and because of the adequacy of the infrastructure to transport oil, NGLs and natural gas in the areas in which we
operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional
customers such that our production volumes would not be materially affected for any significant period of time.
Hedging Activities
We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash
flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. For a more detailed discussion
of our hedging activities, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Results of Operations—Costs and Operating Expenses—Commodity Derivative Transactions,”
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting
Policies and Estimates—Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures About Market
Risk.”
17
Competition
We operate in a highly competitive environment for leasing and acquiring properties and in securing trained
personnel. Our competitors specifically include major and independent oil and natural gas companies that operate in our
project areas. These competitors include, but are not limited to, Carrizo Oil & Gas, Inc., Chesapeake Energy
Corporation, EOG Resources, Inc., Marathon Oil Corporation, and Noble Energy, Inc. Many of our competitors possess
and employ financial, technical and personnel resources substantially greater than ours, which can be particularly
important in the areas in which we operate. 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. In addition, there is substantial competition for capital available for investment in
the oil and natural gas industry.
We are also affected by the competition for and the availability of equipment, including drilling rigs and
completion equipment. We are unable to predict when, or if, shortages of such equipment may occur or how they would
affect our development and exploitation programs.
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. After
an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record
corrective assignments as necessary.
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our
properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those
properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the
extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing
any title defects at our expense. We generally will not commence drilling operations on a property until we have cured
any material title defects on such property.
We 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.
Seasonal Nature of Business
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. In addition, certain natural gas users
utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer,
which can lessen seasonal demand fluctuations.
18
Environmental Matters and Regulation
General
Our operations are subject to stringent and complex federal, state and local laws and regulations governing
environmental protection as well as the discharge of materials into the environment or otherwise relating to protection of
the environment or occupational health and safety. Numerous governmental agencies, such as the Environmental
Protection Agency (the "EPA") and the Texas Railroad Commission ("Commission"), issue regulations, which often
require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and
may result in injunctive obligations for failure to comply. These laws and regulations may, among other things (i) require
the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and
concentration of various substances that can be released into the environment or injected into formations in connection
with oil and natural gas drilling, production and transportation activities; (iii) govern the sourcing and disposal of water
used in the drilling and completion process; (iv) limit or prohibit drilling or injection activities on certain lands lying
within wilderness, wetlands, seismically active areas, and other protected areas; (v) require remedial measures to
mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi)
result in the suspension or revocation of necessary permits, licenses and authorizations; (vii) impose substantial liabilities
for pollution resulting from drilling and production operations; and (viii) require that additional pollution controls be
installed. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and
criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance
of some or all of our operations. Furthermore, liability under such laws and regulations is strict (i.e., no showing of
“fault” is required) and can be joint and several.
These laws 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, The U.S. Congress and federal and state agencies
frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste
handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our
operating costs.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may
affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement
policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements
could have a material adverse effect on our financial position and results of operations. Moreover, accidental releases or
spills may occur in the course of our operations, and we could incur significant costs and liabilities as a result of such
releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe
that we are in substantial compliance with existing laws and regulations and that continued compliance with existing
requirements will not materially affect us, there is no assurance that this situation will continue in the future.
The following is a summary of the more significant existing environmental, health and safety laws and
regulations to which our business operations are subject and for which compliance may have a material adverse impact
on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
Our operations are subject to environmental laws and regulations relating to the management and release of
hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the
generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in
some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances
may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as
amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to
fault or legality of conduct, on classes of persons considered to be responsible for the release, deemed "responsible
parties," of a "hazardous substance" into the environment. These persons include the current owner or operator of the site
where the release occurred, past owners or operators at the time a hazardous substance was released at the site, and
19
anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such
persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and for the costs of certain health studies.
CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or
the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon
for neighboring landowners and other third parties to file common law-based claims for personal injury and property
damage allegedly caused by hazardous substances or other pollutants released into the environment. We generate
materials in the course of our operations that may be regulated as hazardous substances, and despite the "petroleum
exclusion" of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle
hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations
and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at
which these hazardous substances have been released into the environment. In addition, we may have liability for
releases of hazardous substances at our properties by prior owners or operators or other third parties.
The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their
implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous
and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can
seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state
requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration,
development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste
under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state
laws or other federal laws. It is possible, however, that certain oil and natural gas exploration, development and
production wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be
subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in
The U.S. Congress to re-categorize certain oil and natural gas exploration and production wastes as "hazardous wastes."
Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material
adverse effect on our results of operations and financial position.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration,
production and processing for many years. Although we believe that we are in substantial compliance with the
requirements of CERCLA, RCRA, and related state and local laws and regulations, that we hold all necessary and up-to-
date permits, registrations and other authorizations required under such laws and regulations and that 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, under or from the properties owned or leased by us, or on, under or from other
locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous owners or operators whose treatment and disposal of
hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed
or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we
could be required to undertake response or corrective measures, which could include removal of previously disposed
substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations
to prevent future contamination.
Water and Other Water Discharges and Spills
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking
Water Act, or the SDWA, the Oil Pollution Act of 1990, or the OPA, and analogous state laws, impose restrictions and
strict controls with respect to the discharge of pollutants, including oil, produced waters and other hazardous substances,
into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with
the terms of a permit issued by EPA or an analogous state agency. The discharge of dredge and fill material in regulated
waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of
Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production
facilities to obtain individual permits or coverage under general permits for storm water discharges. Some states also
maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater
20
conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and
regulation.
Furthermore, the EPA is examining regulatory requirements for “indirect dischargers” of wastewater – i.e.,
those that send their discharges to private or publicly owned treatment facilities, which treat the wastewater before
discharging it to regulated waters. On April 7, 2015, the EPA published a proposed rule establishing federal pre-
treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to publicly
owned treatment works (“POTWs”). The EPA asserts that wastewater from such facilities can be generated in large
quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from the
POTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to
pre-treat wastewater before transferring it to POTWs. The public comment period ended on July 17, 2015, and the EPA
is expected to publish a final rule by August 2016. The EPA is also conducting a study of private wastewater treatment
facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater.
The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater,
available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT
facilities, and the environmental impacts of discharges from CWT facilities.
Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution
prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Obtaining
permits also has the potential to delay the development of oil and natural gas projects. These same regulatory programs
also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to
incur compliance costs.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-
compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and
regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water
Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters
in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws
require individual permits or coverage under general permits for discharges of storm water runoff from certain types of
facilities. The OPA amends the Clean Water Act and establishes strict liability and natural resource damages liability for
unauthorized discharges of oil into waters of the United States. The OPA is the primary federal law imposing oil spill
liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into
waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities
near or crossing waterways must maintain certain significant levels of financial assurance to cover potential
environmental cleanup and restoration costs, as well as prepare Facility Response Plans for responding to a worst case
discharge of oil into waters of the United States. Under the OPA, strict and joint and several liability may be imposed on
"responsible parties" for all containment and cleanup costs and certain other damages arising from a release, including,
but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting
from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United
States. A "responsible party" includes the owner or operator of an onshore facility. These laws and any implementing
regulations may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to
these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of
wastewater or storm water and the underground injection of fluids and are required to develop and implement SPCC
plans, in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits
necessary to conduct our operations, and we believe we are in substantial compliance with their terms.
It is customary to recover oil and natural gas from deep shale formations through the use of hydraulic
fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and
chemical additives under pressure into rock formations to stimulate oil and natural gas production. The protection of
groundwater quality is extremely important to us. We believe that we follow all state and federal regulations and apply
industry standard practices for groundwater protection in our operations. These measures are subject to close supervision
by state and federal regulators. Our policy and practice is to follow all applicable guidelines and regulations in the areas
where we conduct hydraulic fracturing. Accordingly, we set surface casing strings below the deepest usable quality fresh
water zones and cement them back to the surface in accordance with applicable regulations, potential lease requirements
21
and other legal requirements to ensure protection of existing fresh water zones. Also, prior to commencing drilling
operations for the production portion of the hole, the surface casing strings are pressure tested to ensure mechanical
integrity.
The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the
Underground Injection Control, or UIC, Program. Hydraulic fracturing is generally exempt from regulation under the
UIC Program, and thus the hydraulic fracturing process is typically regulated by state oil and natural gas commissions.
The EPA, however, has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under
the UIC Program. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas
hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells,
which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address
the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the
permitting authority for UIC Class II programs in Texas, Mississippi, and Louisiana, where we maintain acreage, the
EPA is encouraging state programs to review and consider use of the above-mentioned guidance. Furthermore,
legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground
injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to
require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent
sessions of The U.S. Congress.
On May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its
intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information
related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. The
EPA plans to develop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed
mechanism – regulatory, voluntary, or a combination of both – to collect data on hydraulic fracturing chemical
substances and mixtures.
In addition, on March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing
hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic
fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to BLM
of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures,
and the depths of all usable water. The rule took effect on June 24, 2015, although it is the subject of several pending
lawsuits filed by industry groups and at least four states, alleging that federal law does not give the BLM authority to
regulate hydraulic fracturing. On September 30, 2015, the United States District Court for Wyoming issued a preliminary
injunction preventing BLM from implementing the rule nationwide. This order has been appealed to the Tenth Circuit
Court of Appeals.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on
environmental aspects of hydraulic fracturing practices. For example, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities. In June 2015, the EPA released its draft assessment report for
peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing
activities could potentially impact drinking water resources, there is no evidence available showing that those
mechanisms have led to widespread, systemic impacts. Also, on February 6, 2015, the EPA released a report with
findings and recommendations related to public concern about induced seismic activity from disposal wells. The report
recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other
governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government
Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing.
These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained,
could spur initiatives to further regulate hydraulic fracturing or the disposal of produced water and flowback fluid in
underground injection wells under the SDWA or other regulatory mechanism. Also, some states have adopted, and other
states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise
require the public disclosure of chemicals used in the hydraulic fracturing process. For example, in December 2011, the
Commission adopted rules and regulations requiring that hydraulic fracturing well operators disclose the list of chemical
ingredients subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, to
22
state regulators and the public. Also, in May 2013, the Commission adopted new rules governing well casing, cementing
and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The
new rules took effect in January 2014. Additionally, on October 28, 2014, the Commission adopted disposal well rule
amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous
produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological
Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles
around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17,
2014, also clarify the Commission's authority to modify, suspend or terminate a disposal well permit if scientific data
indicates a disposal well is likely to contribute to seismic activity. The Commission has used this authority to deny
permits for waste disposal sites.
These or any other new laws or regulations that significantly restrict hydraulic fracturing or the disposal of
produced water and flowback fluid in underground injection wells could make it more difficult or costly for us to drill
and produce from conventional and tight formations as well as make it easier for third parties opposing the hydraulic
fracturing process to initiate legal proceedings. If hydraulic fracturing is regulated at the federal level, fracturing
activities could become subject to additional permitting and financial assurance requirements, more stringent
construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment
requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could
cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could
have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to
estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing
is enacted into law.
Air Emissions
The federal Clean Air Act, as amended, or the CAA, and comparable state laws, regulate emissions of various
air pollutants through air emissions standards, construction and operating permitting programs and the imposition of
other compliance requirements. In addition, the EPA has developed, and continues to develop, stringent regulations
governing emissions of toxic air pollutants at specified sources. On August 16, 2012, the EPA published final rules that
subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New
Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”)
programs. The rule includes NSPS for completions of hydraulically fractured gas wells and establishes specific new
requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and
certain other equipment. The final rule seeks to achieve a 95% reduction in Volatile Organic Compounds (“VOCs”)
emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically fractured wells
constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules
from both industry and the environmental community, and court challenges to the rules were also filed. In response, the
EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.
For example, in September 2013 and December 2014, the EPA amended its rules to extend compliance deadlines and to
clarify the NSPS. Further, on July 31, 2015, the EPA finalized two updates to the NSPS to address the definition of low-
pressure wells and references to tanks that are connected to one another (referred to as connected in parallel). In addition,
on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and VOC emissions from oil and
gas industry, including new “downstream” requirements covering equipment in the natural gas transmission segment of
the industry that was not regulated by the 2012 rules. The public comment period closed on December 4, 2015.
Also, on January 22, 2016, the BLM announced a proposed rule to reduce the flaring, venting and leaking of
methane from oil and gas operations on federal and Indian lands. The proposed rule would require operators to use
currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and
replace outdated equipment that vents large quantities of gas into the air. The rule would also clarify when operators owe
the government royalties for flared gas.
These laws and regulations may require us to obtain pre-approval for the construction or modification of certain
projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent
air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has
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the potential to delay the development of oil and natural gas projects, and our failure to comply with these requirements
could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal
enforcement actions. While we may be required to incur certain capital expenditures in the next few years for air
pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a
material adverse effect on our operations.
Climate Change
On December 15, 2009, the EPA 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 the warming of the earth's atmosphere and other climate changes. These
findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing
provisions of the CAA. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding
possible future regulation of GHG emissions under the CAA. The motor vehicle rule, which became effective in July
2010, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (the
"Tailoring Rule") in May 2010, and it became effective in January 2011. The Tailoring Rule established new GHG
emissions thresholds that determine when stationary sources must obtain permits under the PSD and Title V programs of
the CAA. On June 23, 2014, in Utility Air Regulatory Group v. EPA ("UARG v. EPA"), the Supreme Court held that
stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The
Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at
sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memorandums
providing initial guidance on GHG permitting requirements in response to the Court's decision in UARG v. EPA. In its
preliminary guidance, the EPA indicates it will undertake a rulemaking action to rescind any PSD permits issued under
the portions of the Tailoring Rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted "no
action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and
conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On
April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the
invalid regulations.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large
GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution
companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule
expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage,
and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with
reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule
to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells
using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
In addition, the EPA has continued to adopt GHG regulations of other industries, such as its August 2015
adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final
Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon
dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission
guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as
industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals.
In addition, the U.S. Congress has from time to time considered 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. Most of these cap and
trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender
emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG
emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of
allowances is expected to escalate significantly. Furthermore, some states have enacted renewable portfolio standards,
which require utilities to purchase a certain percentage of their energy from renewable fuel sources. Although the U.S.
Congress has not adopted comprehensive GHG legislation at this time, it may do so in the future, and many states
continue to pursue regulations to reduce GHG emissions.
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Furthermore, in December 2015, the United States joined the international community at the 21st Conference of
the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting
Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to
conserve and enhance sinks and reservoirs of GHGs. The Agreement, if ratified, establishes a framework for the parties
to cooperate and report actions to reduce GHG emissions.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. The
adoption of any legislation or regulations that otherwise limit emissions of GHGs from our equipment and operations,
could require us to incur increased operating costs to monitor and report on GHG emissions or reduce emissions of
GHGs associated with our operations, such as costs to purchase and operate emissions control systems, to acquire
emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory
programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect
demand for the oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG
emissions could have an adverse effect on our business, financial condition and results of operations.
In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and
natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private
individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or
property damages. While our business is not a party to this litigation, we could be named in actions making similar
allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse
impact on our financial condition.
Moreover, 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.
National Environmental Policy Act
Oil and natural gas exploration, development and production activities on federal lands are subject to the
National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the DOI, 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 to evaluate 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. Currently, we have minimal exploration and
production activities on federal lands. For those current activities, however, as well as for future or proposed exploration
and development plans, on federal lands, governmental permits or authorizations that are subject to the requirements of
NEPA are required. This process has the potential to delay the development of oil and natural gas projects.
Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.
Endangered Species Act
Additionally, environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact
exploration, development and production activities on public or private lands. The ESA provides broad protection for
species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of
endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal
agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the
continued existence of listed species or modify their critical habitat. While some of our facilities on federal lands may be
located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial
compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified
endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary
for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to
operating restrictions or bans in the affected areas.
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Occupational Safety and Health Act
We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the
health and safety of employees. In addition, OSHA's hazard communication standard requires that information be
maintained about hazardous materials used or produced in our operations and that this information be provided to
employees, state and local government authorities and citizens. We believe that our operations are in substantial
compliance with the OSHA requirements.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.
Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual
members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and
natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens
generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and
natural gas industry with similar types, quantities and locations of production.
Legislation continues to be introduced in The U.S. Congress, and the development of regulations continues in
the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil
and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that
compliance with these laws will have a material adverse impact on us.
Drilling and Production
Our operations are subject to various types of regulation at federal, state and local levels. These types of
regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most
states, and some counties and municipalities, in which we operate also regulate one or more of the following:
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the location of wells;
the method of drilling and casing wells;
the disclosure of the chemicals used in the hydraulic fracturing process;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of
oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while
other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be
implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws
establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural
gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of
oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill.
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.
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Natural Gas Regulation
The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate
transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms,
conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy
Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to natural gas
pipeline transportation. FERC's regulations for interstate natural gas transmission in some circumstances may also affect
the intrastate transportation of natural gas.
The FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and
transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial
enforcement authority for violations of the Natural Gas Act, or NGA, including the ability to assess civil penalties, order
disgorgement of profits and recommend criminal penalties. The Energy Policy Act of 2005 amended the NGA to grant
FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in
interstate commerce, and to prohibit market manipulation. FERC's anti-manipulation regulations apply to FERC
jurisdictional activities, which have been broadly construed by the FERC. Should we fail to comply with all applicable
FERC-administered statutes, rules, regulations and orders, we could be subject to substantial civil and criminal penalties,
including civil penalties of up to $1.0 million per day, per violation.
In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry.
Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level,
including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their
wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a
gas index. The FERC also contemplated expanding the industry's reporting requirements. On November 15, 2012, the
FERC issued a Notice of Inquiry seeking comments whether requiring quarterly reporting of every gas transaction within
the FERC's jurisdiction that entails physical delivery for the next day or the next month would provide useful
information for improving natural gas market transparency. The FERC ultimately determined that imposing a quarterly
reporting requirement is not necessary at this time and exercised its discretion to terminate the Notice of Inquiry on
November 17, 2015.
Although natural gas prices are currently unregulated, The U.S. Congress historically has been active in the area
of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by The U.S. Congress or the various state legislatures, and what effect, if
any, the proposals might have on the operations of our properties. Sales of condensate and NGLs are not currently
regulated and are made at market prices.
State Regulation
The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas,
including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently
imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate
the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas
resources. States may regulate rates of production and may establish maximum daily production allowables from natural
gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in
other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of
these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number
of wells or locations we can drill.
The oil and natural gas industry is also subject to compliance with various other federal, state and local
regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not
believe that compliance with these laws will have a material adverse effect on us.
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Employees
We currently do not have any employees. Pursuant to our Services Agreement with SOG (the “Services
Agreement”), SOG performs services for us, including the operation of our properties. Please also read Note 9, “Related
Party Transactions.” As of December 31, 2015, SOG had approximately 200 employees, including 25 engineers, 11
geoscientists and 16 land professionals. None of these employees are represented by labor unions or covered by any
collective bargaining agreement. We believe that SOG’s relations with its employees are satisfactory.
We also contract for the services of independent consultants involved in land, engineering, regulatory,
accounting, financial and other disciplines as needed.
Offices
For our principal offices, we currently share offices with other members of the Sanchez Group under leases
entered into by the Company covering approximately 90,000 square feet of office space in Houston, Texas at 1000 Main
Street, Suite 3000, Houston, Texas 77002, expiring in 2025. In addition, SOG maintains offices in Laredo and San
Antonio, Texas.
Available Information
We are required to file annual, quarterly and current reports, proxy statements and other information with the
SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F
Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document
retrieval services and at the SEC’s website at http://www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “SN.”
Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New
York Stock Exchange, 20 Broad Street, New York, New York 10005.
We also make available on our website at http://www.sanchezenergycorp.com all of the documents that we file
with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC.
Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.
Item 1A. Risk Factors
Our business involves a high degree of risk. You should consider and read carefully all of the risks and
uncertainties described below, together with all of the other information contained in this Annual Report on Form 10-K,
including the financial statements and the related notes appearing at the end of this Annual Report on Form 10-K. If any
of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our
business, business prospects, financial condition, results of operations or cash flows could be materially adversely
affected. The risks below are not the only ones facing our company. Additional risks not currently known to us or that we
currently deem immaterial may also adversely affect us. This Annual Report on Form 10-K also contains
forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could
differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the
risks described below.
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Risks Related to Our Business
Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result
in any discoveries or additions to our future production or reserves. Any material inaccuracies in estimated reserves,
estimated drilling costs or underlying assumptions will materially affect our business.
Exploring for and developing oil and natural gas reserves involves a high degree of operational and financial
risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The
budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when
drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling
may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and
mechanical difficulties. Exploratory wells bear a much greater risk of loss than development wells. Moreover, the
successful drilling of an oil or natural gas well does not ensure a profit on investment. A variety of factors, both
geological and market-related, can cause a well to become uneconomic or only marginally economic. Our initial drilling
locations, and any potential additional locations that may be developed, require significant additional exploration and
development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling
and development costs are significantly more than our estimated costs, we may not be able to continue our business
operations as proposed and would be forced to modify our plan of operation.
Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities
and present value of our estimated reserves.
Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves and future
production. It is not possible to measure underground accumulations of oil, natural gas and NGLs in an exact way. Oil,
natural gas and NGL reserve engineering is complex, requiring subjective estimates of underground accumulations of
oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGL prices, future production levels
and operating and development costs. In estimating our level of oil, natural gas and NGL reserves, we and our
independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating
to:
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the level of oil, natural gas and NGL prices;
future production levels;
capital expenditures;
operating and development costs;
the effects of regulation;
the accuracy and reliability of the underlying engineering and geologic data; and
the availability of funds.
If these assumptions prove to be incorrect, our estimates of our 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 our estimates of the future net cash flows from our estimated reserves could change
significantly. For example, with other factors held constant, if the commodity prices used in our reserve report as of
December 31, 2015 had decreased by 10%, then the standardized measure of our estimated proved reserves as of that
date would have decreased by approximately $200.7 million, from approximately $593.5 million to approximately
$392.8 million.
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Our standardized measure is calculated using unhedged oil, natural gas and NGL prices and is determined in
accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to
take into account changes in our assumptions and the results of actual development and production.
The reserve estimates we make for wells or fields that do not have a lengthy production history are less reliable
than estimates for wells or fields with lengthy production histories. A lack of production history may contribute to
inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
Prospects that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.
Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of
drilling and testing whether any particular prospect will yield oil, natural gas or NGLs in sufficient quantities to recover
drilling or completion costs or to be economically viable. The use of seismic data and other technologies, and the study
of producing fields in the same area, will not enable us to know conclusively before drilling whether oil, natural gas or
NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in commercially viable quantities.
Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields
may not be applicable to our drilling prospects.
Our estimated oil, natural gas and NGL reserves will naturally decline over time, and we may be unable to develop,
find or acquire additional reserves to replace our current and future production at acceptable costs, which would
adversely affect our business, financial condition and results of operations.
Our future oil, natural gas and NGL reserves, production volumes, and cash flow depend on our success in
developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves
economically. Our estimated oil, natural gas and NGL reserves will naturally decline over time as they are produced. Our
success depends on our ability to economically develop, find or acquire additional reserves to replace our own current
and future production. If we are unable to do so, or if expected development is delayed, reduced or cancelled, the average
decline rates will likely increase.
Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that
could adversely affect our business, financial condition and results of operations.
The cost of developing, completing and operating a well is often uncertain, and cost factors can adversely affect
the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not
produce as much oil, natural gas and NGLs as we had estimated. In addition, our use of 2D and 3D seismic data and
visualization techniques to identify subsurface structures and hydrocarbon indicators do not enable the interpreter to
know whether hydrocarbons are, in fact, present in those structures and requires greater pre-drilling expenditures than
traditional drilling strategies. Furthermore, our development and production operations may be curtailed, delayed or
canceled as a result of other factors, including:
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high costs, shortages or delivery delays of rigs, equipment, labor or other services;
composition of sour gas, including sulfur and mercaptan content;
unexpected operational events and conditions;
reductions in oil, natural gas and NGL prices;
increases in severance taxes;
adverse weather conditions and natural disasters;
facility or equipment malfunctions and equipment failures or accidents, including acceleration of
deterioration of our facilities and equipment due to the highly corrosive nature of sour gas;
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title problems;
pipe or cement failures, casing collapses or other downhole failures;
compliance with ever-changing environmental and other governmental requirements;
environmental hazards, such as natural gas leaks, oil, natural gas and NGL spills, salt water spills, pipeline
ruptures, discharges of toxic gases or other releases of hazardous substances;
lost or damaged oilfield development and service tools;
unusual or unexpected geological formations and pressure or irregularities in formations;
loss of drilling fluid circulation;
fires, blowouts, surface craterings and explosions;
uncontrollable flows of oil, natural gas, NGL or well fluids;
loss of leases due to incorrect payment of royalties;
limited availability of financing at acceptable rates; and
other hazards, including those associated with sour gas such as an accidental discharge of hydrogen sulfide
gas, that could also result in personal injury and loss of life, pollution and suspension of operations.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our
investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially
and adversely affect our business, financial condition and results of operations.
We routinely apply hydraulic fracturing techniques in many of our drilling and completion operations.
Hydraulic fracturing has recently become subject to increased public scrutiny and recent changes in federal and state law,
as well as proposed legislative changes, could significantly restrict the use of hydraulic fracturing. Such laws could make
it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations
and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill
wells. In addition, such laws could make it easier for third parties opposing the hydraulic fracturing process to initiate
legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect
groundwater. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory
initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting
requirements and result in permitting delays, financial assurance requirements, more stringent construction
specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements,
as well as potential increases in costs. Please read “—Federal and state legislative and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Item 1.
Business—Environmental Matters and Regulation—Water and Other Water Discharges and Spills.”
Additionally, hydraulic fracturing, drilling, transportation and processing of hydrocarbons bear an inherent risk
of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value
associated with the affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines,
penalties or damages associated with any of the foregoing consequences.
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Our acquisition, development and production operations require us to make substantial capital expenditures.
Although we expect to fund our capital expenditure budget for 2016 using cash flow from operations and cash on
hand, if our cash flow from operations turns out to be less than we currently expect and we are required, but are
unable, to fund our remaining capital budget from other sources, such as borrowings under our credit facility and/or
the issuance of debt or equity securities, our failure to obtain the funds that we need could have a material adverse
effect on our business, financial condition and results of operations.
The oil and natural gas industry in which we operate is capital intensive and we must make substantial capital
expenditures in our business for the acquisition, development and production of oil, natural gas and NGL reserves. Our
cash on hand, cash flows from operations, ability to borrow and access to capital markets are subject to a number of
variables, many of which are beyond our control, including:
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our estimated proved oil, natural gas and NGL reserves;
the amount of oil, natural gas and NGLs we produce;
the prices at which we sell our production;
the results of our hedging strategy;
the costs of developing, producing, and transporting our oil, natural gas and NGL assets, including costs
attributable to governmental regulation and taxation;
our ability to acquire, locate and produce new reserves;
fluctuations in our working capital needs;
interest payments, debt service and dividend payment requirements;
prevailing economic and capital markets conditions, especially for oil and gas companies;
our financial condition; and
the ability and willingness of banks and other lenders to lend to us.
Continued decreases in our revenues or the borrowing base under our revolving credit facility as a result of
lower oil, NGL or natural gas prices, operating difficulties, declines in reserves or for any other reason, will adversely
impact our ability to obtain the capital necessary to sustain our operations at current levels. In addition, we may be
unable to access the capital markets for debt or equity financing. If we are unsuccessful in obtaining the funds we need to
fund our capital budget, we will be forced to reduce our capital expenditures, which in turn could lead to a decline in our
production, revenues and our reserves, and could adversely affect our business, financial condition and results of
operations.
Market conditions for oil, natural gas and NGLs, and particularly the recent declines in prices for these commodities,
have, and are expected to continue to adversely affect our revenue, cash flows, profitability and growth.
Prices for oil, natural gas and NGLs fluctuate widely in response to a variety of factors that are beyond our
control, such as:
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domestic and foreign supply of and demand for oil, natural gas and NGLs;
• weather conditions and the occurrence of natural disasters;
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overall domestic and global economic conditions;
political and economic conditions in oil, natural gas and NGL producing countries globally, including
terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war;
actions of OPEC and other state-controlled oil companies relating to oil price and production controls;
the effect of increasing liquefied natural gas and exports from the United States;
the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices;
technological advances affecting energy supply and energy consumption;
domestic and foreign governmental regulations, including regulations prohibiting or restricting our ability
to apply hydraulic fracturing to our wells, and taxation;
the impact of energy conservation efforts;
the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation
facilities;
the availability of refining capacity; and
the price and availability of alternative fuels.
In the past, oil, natural gas and NGL prices have been extremely volatile, and we expect this volatility to
continue. Beginning in the latter part of 2014, oil prices declined precipitously, and continued to decline throughout 2015
as well as the start of 2016. The West Texas Intermediate posted price used to calculate the full cost ceiling in
accordance with SEC rules declined from a high of $105.34 per bo on July 1, 2014 to $69.00 per bo on December 1,
2014, and $41.85 per bo on December 31, 2015. Such volatility has negatively affected the amount of our net estimated
proved reserves and has negatively affected the standardized measure of discounted future net cash flows of our net
estimated proved reserves. We recorded a full cost ceiling test impairment before income taxes of $213.8 million for the
year ended December 31, 2014, and we recorded a full cost ceiling impairment test impairment after income taxes of
$1,365 million for the year ended December 31, 2015. The impact of lower commodity prices adversely affecting proved
reserve values primarily contributed to the ceiling impairment. Changes in production rates, prices, levels of reserves,
future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test
calculation and impairment analyses in future periods. Given the current trend in commodity prices, the Company
expects a continued decline in the 12-month average commodity prices, and therefore, additional impairments could be
recorded during 2016.
In addition, our revenue, profitability and cash flow depend upon the prices of and demand for oil, natural gas
and NGL reserves, and a sustained drop in prices has significantly and is expected to continue to affect our financial
results and impede our growth. In particular, sustained declines in commodity prices will:
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limit our ability to enter into commodity derivative contracts at attractive prices;
reduce the value and quantities of our reserves, because declines in oil, natural gas and NGL prices would
reduce the amount of oil, natural gas and NGLs that we can economically produce;
reduce the amount of cash flow available for capital expenditures;
limit our ability to borrow money or raise additional capital; and
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• make it uneconomical for our operating partners to commence or continue production levels of oil, natural
gas and NGLs.
An increase in the differential between the NYMEX or other benchmark prices of oil, natural gas and NGLs and the
wellhead price we receive for our production could adversely affect our business, financial condition and results of
operations.
The prices that we receive for our oil, natural gas and NGL production sometimes reflect differences between
the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between
the benchmark price and the price we receive is called a basis differential. Increases in the basis differential between the
benchmark prices for oil, natural gas and NGLs and the wellhead price we receive could adversely affect our business,
financial condition and results of operations. We do not have or currently plan to have any commodity derivative
contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be
exposed to any increase in such differentials, which could adversely affect our business, financial condition and results
of operations.
As of February 26, 2016, we have commodity derivative contracts in place covering approximately 70% of the
mid-point of our estimated oil and natural gas production for 2016. The contracts consist of swaps and put spreads
covering crude oil and natural gas production. In the future, we expect to continue to enter into commodity derivative
contracts for a portion of our estimated production, which could result in net gains or losses on commodity derivatives.
Our hedging strategy and future hedging transactions will be determined by our management, which is not under any
obligation to enter into commodity derivative contracts covering any specific portion of our production.
The prices at which we enter into commodity derivative contracts covering our production in the future will be
dependent upon oil, natural gas and NGL prices at the time we enter into these transactions, which may be substantially
higher or lower than past or current oil, natural gas and NGL prices. Accordingly, our price hedging strategy may not
protect us from significant declines in oil, natural gas and NGL prices realized for our future production. Conversely, our
hedging strategy may limit our ability to realize incremental cash flows from commodity price increases. As such, our
hedging strategy may not protect us from changes in oil, natural gas and NGL prices that could have a significant
adverse effect on our liquidity, business, financial condition and results of operations.
Economic uncertainty could negatively impact the prices for oil, natural gas and NGLs, limit access to the credit and
equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict.
If our cash flow from operations is less than anticipated and our access to capital is restricted because of
economic uncertainty, we may be required to reduce our operating and capital budget, which could have a material
adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize
in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult and
less economic to consummate. Additionally, demand for oil, natural gas and NGLs may deteriorate and result in lower
prices for oil, natural gas and NGLs, which could have a negative impact on our revenues. Lower prices could also
adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be
ineffective if our counterparties are unable to perform their obligations.
Lower oil, natural gas and NGL prices have caused us to record ceiling limitation impairments, reducing our
earnings and our stockholders’ equity and further declines in commodity prices may cause us to record further
impairments, which would reduce our earnings and stockholders’ equity.
We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the
acquisition, exploration and development of oil, natural gas and NGL properties, including unproved and unevaluated
property costs. Under full cost accounting rules, the net capitalized cost of oil, natural gas and NGL properties may not
exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from net proved reserves,
discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as
required by SEC rules. If net capitalized costs of oil, natural gas and NGL properties exceed the ceiling limit, we must
charge the amount of the excess to earnings, which could have a material adverse effect on our results of operations for
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the periods in which such charges are taken. This is called a “ceiling limitation impairment.” The risk that we will
experience a ceiling limitation impairment increases when oil, natural gas or NGL prices are depressed as in the current
environment, if we have substantial downward revisions in estimated net proved reserves or if estimates of future
development costs increase significantly. Based upon current price trends we could experience ceiling limitation
impairments in future periods.
Given the decline in commodity prices throughout 2015, in each of the first three quarters of 2015, the net book
value of our oil and natural gas properties exceeded our ceiling amount using the WTI unweighted 12-month average
price adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and
other factors affecting the price realized at the wellhead, resulting in a total write-down of our oil and natural gas
properties of $1,365 million after income taxes. As ceiling test computations depend upon the calculated unweighted
arithmetic average prices, it is difficult to predict the likelihood, timing and magnitude of any future impairments.
However, given the current trend in commodity prices, the Company expects a continued decline in 12-month average
commodity prices, and, therefore, additional impairments could be recorded during 2016. A ceiling test write down
would negatively affect our results of operations.
Costs associated with unevaluated properties are not initially subject to the ceiling test limitation. Rather, we
assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value
based upon our intentions, as approved by our board of directors and management, with respect to drilling on such
properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved
reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly
influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable
cost. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such
property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to
amortization and the ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond
our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to
amortization and the ceiling test limitation.
Lower oil and natural gas prices also reduces the amount of oil and natural gas that we can produce
economically. Substantial and sustained decreases in oil and natural gas prices would render uneconomic a significant
portion of our development and exploitation projects. This may result in our having to make downward adjustments to
our estimated proved reserves. As a result, substantial and sustained declines in oil and natural gas prices may materially
and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned
capital expenditures.
The Company’s derivative risk management activities could result in financial losses.
To mitigate the effect of commodity price volatility on the Company’s net cash provided by operating activities,
support the Company’s annual capital budgeting and expenditure plans and reduce commodity price risk associated with
certain capital projects, the Company’s strategy is to enter into derivative arrangements covering a portion of its oil,
NGL and natural gas production. These derivative arrangements are subject to mark-to-market accounting treatment, and
the changes in fair market value of the contracts are reported in the Company’s statements of operations each quarter,
which may result in significant non-cash gains or losses. After the current hedges expire, there is significant uncertainty
that we will be able to put new hedges in place that will provide us with the same benefit. These derivative contracts may
also expose the Company to risk of financial loss in certain circumstances, including when:
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•
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production is less than the contracted derivative volumes, in which case we might be forced to satisfy all or
a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying
physical commodity;
the counterparty to the derivative contract defaults on its contractual obligations;
there is a widening of price basis differentials between delivery points for our production and the delivery
point assumed in the hedge instrument; or
35
•
the derivative contracts limit the benefit the Company would otherwise receive from increases in
commodity prices.
Such financial losses could materially impact our liquidity, business, financial condition and results of operations.
Our stock price has been volatile, and investors in our common stock could incur substantial losses.
Our stock price has been volatile. For example, during the year ended December 31, 2014, our stock price had a
high closing price of $38.13 per share and for the year ended December 31, 2015 our stock price had a low closing price
of $3.64 per share. As a result of this volatility, investors may not be able to sell their common stock at or above the
price at which they purchased their shares. The market price for our common stock may be influenced by many factors,
including, but not limited to:
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the price of oil, NGLs and natural gas;
the success of our exploration and development operations, and the marketing of any oil we produce;
regulatory developments in the United States;
the recruitment or departure of key personnel;
quarterly or annual variations in our financial results or those of companies that are perceived to be similar
to us;
• market conditions in the industries in which we compete and issuance of new or changed securities;
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analysts’ reports or recommendations;
the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;
the inability to meet the financial estimates of analysts who follow our common stock;
our issuance of any additional securities;
investor perception of our company and of the industry in which we compete; and
general economic, political and market conditions.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless
production is established on units containing the acreage or the leases are extended.
Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production in paying
quantities is established during their primary terms or we obtain extensions of the leases. Our drilling plans for our
undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our
control, such as drilling results, oil, natural gas and NGL prices, the availability and cost of capital, drilling and
production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints
and regulatory approvals. Because of these uncertainties, we do not know if our undeveloped leasehold acreage will ever
be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential drilling
locations. If our leases expire and we do not have them held by production, we will lose our right to develop the related
properties on this acreage. As of December 31, 2015, approximately 71% of our acreage was held by production. We
have leases that were not held by production representing 15,383 net acres (11,137 of which were in the Eagle Ford
Shale) expiring in 2016, 15,522 net acres (12,249 of which were in the Eagle Ford Shale) expiring in 2017, and 44,355
net acres (9,192 of which were in the Eagle Ford Shale) expiring in 2018 and beyond. While we anticipate that our
current and future drilling plans will address the majority of our leases expiring in the Eagle Ford Shale in 2016, our
actual drilling activities may materially differ from those presently identified, which could adversely affect our business,
financial condition and results of operation.
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As a result of commodity prices, we have deferred development plans in the TMS to beyond 2016. As a result
of the deferment of development in this area, we expect to have approximately 4,200 acres expire in 2016 in the TMS.
There are currently no proved undeveloped reserves booked in the TMS. Changes to technology, prices, or commodity
prices may cause us to alter our decision to defer development beyond 2016. In addition, we continue to believe that
there is significant long term upside associated with the play and plan to review leasing and renewal opportunities
throughout the year that may reduce the amount of acreage lost in the play. See “Business and Properties—Properties—
Developed and Undeveloped Acreage” for additional information.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to
uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified and scheduled drilling locations as an estimation of our future
drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth
strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability
of capital, seasonal conditions, regulatory approvals, oil, NGL and natural gas prices, costs and drilling results. Because
of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled
or if we will be able to produce oil, NGL or natural gas from these or any other potential drilling locations. As such, our
actual drilling activities may materially differ from those presently identified, which could adversely affect 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
revenue.
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and properties,
marketing oil, NGLs and natural gas, and securing equipment and trained personnel. Many of our competitors are large
independent oil and natural gas companies that possess and employ financial, technical and personnel resources
substantially greater than those of the Sanchez Group. Those entities may be able to develop and acquire more properties
than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in
the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly
competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry
on refining operations and market petroleum and other products on a regional, national or worldwide basis. These
companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater
number of properties than our financial, technical or personnel resources permit. In addition, there is substantial
competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability
to continue development activities during periods of low oil, NGL and natural gas prices and to absorb the burden of
present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate
sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to
intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively
with larger companies could have a material adverse impact on our business, financial condition and results of
operations.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately
insured.
There are a variety of operating risks inherent in our wells and other operating properties and facilities, such as
leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any
of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal
injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and
substantial revenue losses. The location of our wells and other operating properties and facilities near populated areas,
including residential areas, commercial business centers and industrial sites, could significantly increase the level of
damages resulting from these risks.
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Insurance against all operational risks is not available to us. We are not fully insured against all risks, including
development and completion risks that are generally not recoverable from third parties or insurance. In addition,
pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if
we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could,
therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially reasonable costs or on commercially reasonable terms.
Changes in the insurance markets due to weather, adverse economic conditions, and the aftermath of the Macondo well
incident in the Gulf of Mexico have made it more difficult for us to obtain certain types of coverage. As a result, we may
not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes,
and we cannot be sure the insurance coverage we do obtain will not contain large deductibles or fail to cover certain
hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the
payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of
operations.
Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with
operating in one major contiguous area.
Our current business focus is on the oil and natural gas industry in a limited number of properties, in the Eagle
Ford Shale in South Texas and, to a lesser extent, the TMS in Southwest Mississippi and Southeast Louisiana. Larger
companies have the ability to manage their risk by diversification. However, we currently lack diversification, in terms
of both the nature and geographic scope of our business. For example, our Catarina assets, comprised of approximately
106,000 contiguous net acres in Dimmit, LaSalle and Webb Counties, Texas under the Catarina Lease (the “Catarina
Lease”), represent approximately 66% of our proved reserves as of December 31, 2015, approximately 53% of our Eagle
Ford acreage as of December 31, 2015 and, approximately 72% of our total production volumes for the year ended
December 31, 2015. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions
in which we operate than we would if our business were more diversified, increasing our risk profile. In particular, we
may be disproportionately exposed to the impact of delays or interruptions of production from wells in which we have an
interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment,
facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant
closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from wells in the
Eagle Ford Shale. 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.
We cannot control activities on properties that we do not operate and are unable to control their proper operation and
profitability.
We do not operate all of the properties in which we own an ownership interest. As a result, we have limited
ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties.
The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable
agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and
reserves. The success and timing of our drilling and development activities on properties operated by others therefore
depend upon a number of factors outside of our control, including:
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the nature and timing of the operator’s drilling and other activities;
the timing and amount of required capital expenditures;
the operator’s geological and engineering expertise and financial resources;
the approval of other participants in drilling wells; and
the operator’s selection of suitable technology.
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Our ability to produce oil and natural gas could be impaired if we are unable to acquire adequate supplies of water
for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and
within applicable environmental rules.
Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and
production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives
and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or
disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the
exploration, development or production of oil and natural gas. The Clean Water Act imposes restrictions and strict
controls regarding the discharge of produced waters and other oil and natural gas waste into navigable waters. Permits
must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The
Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized
discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances.
Many state discharge regulations, and the Federal National Pollutant Discharge Elimination System general permits
issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and natural gas industry into coastal waters. The EPA has also adopted regulations requiring
certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. In addition,
some states maintain groundwater protection programs that require permits for discharges or operations that may impact
groundwater conditions. Also, the underground injection of fluids is subject to permitting and other requirements under
state laws and regulation. Public concerns regarding the potential impacts to groundwater and induced seismic activity
have resulted in new proposed requirements related to the underground injection and disposal of fluids. See
“Environmental Matters and Regulation – Water and Other Water Discharges and Spills.”
Furthermore, the EPA is examining regulatory requirements for “indirect dischargers” of wastewater – i.e.,
those that send their discharges to private or publicly owned treatment facilities, which treat the wastewater before
discharging it to regulated waters. On April 7, 2015, the EPA published a proposed rule establishing federal pre-
treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to POTWs.
The EPA asserts that wastewater from such facilities can be generated in large quantities and can contain constituents
that may disrupt POTW operations and/or be discharged, untreated, from the POTW to receiving waters. If adopted, the
new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater before transferring it to
POTWs. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule by August
2016. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste
treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information
related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their
associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of
discharges from CWT facilities.
Compliance with environmental regulations and permit requirements governing the underground injection of
fluids and the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells
may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which
cannot be predicted.
We may lose our rights to the Sanchez Group’s technological database, including its 3D and 2D seismic data, under
certain circumstances.
Pursuant to the Services Agreement, we have access to the unrestricted, proprietary portions of the
technological database owned and maintained by the Sanchez Group and related to our properties, and SOG is otherwise
required to interpret and use the database, to the extent relating to our properties, for our benefit under the Services
Agreement. For a description of the Services Agreement see Note 9, “Related Party Transactions” in the notes to the
consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” of this Annual Report on
Form 10-K. This database includes the 2D and 3D seismic data used for our exploration and development projects as
well as the well logs, LAS files, scanned well documents and other well documents and software that are necessary for
our daily operations. This information is critical for the operation and expansion of our business. Under certain
circumstances, including if SOG provides at least 180 days’ advance written notice of its desire to terminate the Services
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Agreement, the license agreement will terminate and we will lose our rights to this technological database unless
members of the Sanchez Group permit us to retain some or all of these rights, which they may decline to do in their sole
discretion. In such event, we are unlikely to be able to obtain rights to similar information under substantially similar
commercial terms or to continue our business operations as proposed and our liquidity, business, financial condition and
results of operations will be materially and adversely affected and it could delay or prevent an acquisition of us.
Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and
natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools
used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable
geoscientists to know whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We
employ 3D seismic technology with respect to certain of our projects. The implementation and practical use of 3D
seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the
near term, and increase our costs. In addition, the use of 3D seismic and other advanced technologies requires greater
pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and exploration expenses
as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not
be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular
area could decline.
We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of
an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to
acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights
in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial
expenditures to acquire and analyze 3D data without having an opportunity to attempt to benefit from those expenditures.
If we do not purchase additional acreage or make acquisitions on economically acceptable terms, our future growth
will be limited.
Our ability to grow depends in part on our ability to make acquisitions on economically acceptable terms. We
may be unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their
owners;
unable to obtain financing for such acquisitions on economically acceptable terms; or
outbid by competitors.
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved
reserves will decline as a result of our production.
Any acquisitions we complete or geographic expansions we undertake will be subject to substantial risks that could
have a negative impact on our business, financial condition and results of operations.
• Any acquisition involves potential risks, including, among other things:
• mistaken assumptions about estimated proved reserves, future production, revenues, capital expenditures,
operating expenses and costs, including synergies, timing of expected development and the potential for
expiration of underlying leaseholds;
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an inability to successfully integrate the assets or businesses we acquire;
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a decrease in our liquidity by using a significant portion of our cash and cash equivalents to finance
acquisitions;
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any
indemnity we receive is inadequate;
the diversion of management’s attention from other business concerns;
• mistaken assumptions about the overall cost of equity or debt;
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an inability to hire, train or retain qualified personnel to manage and operate our growing business and
assets;
facts and circumstances that could give rise to significant cash and certain non-cash charges; and
customer or key employee losses at the acquired businesses.
Further, we may in the future expand our operations into new geographic areas with operating conditions and a
regulatory environment that may not be as familiar to us as our existing project areas. As a result, we may encounter
obstacles that may cause us not to achieve the expected results of any such acquisitions, and any adverse conditions,
regulations or developments related to any assets acquired in new geographic areas may have a negative impact on our
business, financial condition and results of operations.
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. Our reviews of acquired properties are inherently
incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in
each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not
necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the
properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and
environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is
undertaken.
Our completed acquisitions involve risks associated with acquisitions and integrating acquired assets, including the
potential exposure to significant liabilities, and the intended benefits of these acquisitions may not be realized.
We have grown our business and our reserves through multiple significant acquisitions. Each of these
acquisitions involves certain risks. The risks that we face associated with our acquisitions and integrating the assets
acquired from these acquisitions into existing operations include:
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our senior management’s attention being diverted from the management of daily operations to the
integration of the acquired assets;
our incurring significant unknown and contingent liabilities for which we have limited or no contractual
remedies or insurance coverage;
the acquired assets not performing as well as we anticipate; and
unexpected costs, delays and challenges that arise in integrating such assets into our existing operations.
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Even if we successfully integrate the assets acquired in our acquisitions into our operations, it may not be
possible to realize the full benefits that we anticipate and/or we may not realize these benefits within the expected
timeframe. If we fail to realize the benefits that we anticipate from our acquisitions, our business, results of operations
and financial condition may be adversely affected.
Under the terms of the lease with respect to the Catarina assets, we are subject to annual drilling and development
requirements and failure to comply with these requirements may result in loss of our interests in the Catarina area
that are not held by production.
In order to protect our exploration and development rights in the Catarina area, we are required to meet certain
drilling and other requirements under the Catarina Lease. For example, the Catarina Lease currently requires us to drill
50 wells per year (measured from July to July). If we fail to meet the minimum drilling commitment under the terms of
the Catarina Lease, we would forfeit our acreage under the Catarina Lease and rights to develop land not held by
production (excluding, in certain instances, associated rights such as midstream assets). In addition, the Catarina Lease
requires us to go no longer than 120 days without spudding a well, and, under the terms of the Catarina Lease, failure to
do so would result in the forfeiture of our acreage under the Catarina Lease and rights to develop land not held by
production (excluding, in certain instances, acreage upon which associated midstream assets are located). Our drilling
plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are
beyond our control, such as drilling results, oil, natural gas and NGL prices, the availability and cost of capital, drilling
and production costs, availability of drilling services and equipment, gathering system and pipeline transportation
constraints and regulatory approvals. Because of these uncertainties, we cannot assure you that we will be able meet our
obligations under the Catarina Lease. If the Catarina Lease expires, we will lose our right to develop the related
properties on this acreage, which could adversely affect our business, financial condition and results of operations.
We adopted the Rights Plan, which though it was designed to preserve the value of our NOLs, may discourage the
acquisition and sale of large blocks of our common stock and may result in significant dilution for certain
stockholders.
On July 28, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights plan (the
“Rights Plan”) designed to preserve stockholder value and the value of our NOLs by acting as a deterrent to any person
acquiring beneficial ownership of 4.9% or more of the Company’s outstanding common stock without the approval of
our board of directors. The Rights Plan may discourage existing 5% common stockholders from selling their interest in a
single block, which may impact the liquidity of the Company's common stock, may deter institutional investors from
investing in our common stock, and may deter potential acquirers from making premium offers to acquire the Company,
factors which may depress the market price of our common stock.
If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising
prior to the ownership change to offset future taxable income.
As of December 31, 2015, we had NOLs of $765.9 million. If we were to experience an “ownership change,” as
determined under Section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the
ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An
ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset
our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to
the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is
a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined
in the Internal Revenue Code) at any time during a rolling three-year period.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain
unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our
employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as
processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and
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include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic
security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise
protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect
against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and
controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize,
they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our
operations and could have a material adverse effect on our reputation, financial position, results of operations or cash
flows.
We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other
actions in order to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial
and operating performance, which is subject to prevailing economic and competitive conditions and certain financial,
business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows
from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to
service our indebtedness or to fund our other liquidity needs. If we are unable to generate sufficient cash flows to satisfy
our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt,
selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure you that
any refinancing would be possible, that any assets could be sold or, if sold, of the timing of the sales and the amount of
proceeds that may be realized from those sales, or that additional financing could be obtained on acceptable terms, if at
all. Our credit facility and the indenture governing the Senior Notes (as defined in Note 5, “Long-Term Debt”) contain
restrictions on our ability to dispose of assets and our use of any of the proceeds. Our inability to generate sufficient cash
flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would
materially and adversely affect our financial condition and results of operations.
In addition, if we cannot make scheduled payments on our debt, we will be in default and, as a result:
•
•
our debt holders could declare all outstanding principal and interest to be due and payable;
the lenders under our revolving credit facility could terminate their commitments to lend us money and
foreclose against the assets securing their borrowings; and
• we could be forced into bankruptcy or liquidation.
We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.
Despite our current level of indebtedness, we and our subsidiaries may be able to incur substantial additional
indebtedness in the future, including under our credit facility. As of December 31, 2015, we had $1.75 billion of debt
outstanding, all of which was attributable to our Senior Notes, and a borrowing base of $500 million (with an aggregate
elected commitment amount of $300 million) under our credit facility for secured revolver borrowings. Our increased
indebtedness could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse
macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational
and strategic opportunities. If new debt is added to our current debt levels, the related risks that we and our subsidiaries
now face could intensify.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to
increase significantly.
We will be subject to interest rate risk in connection with borrowings under our credit facility, which bears
interest at variable rates. Interest rate changes will not affect the market value of any debt incurred under such facility,
but could affect the amount of our interest payments, and accordingly, our future earnings and cash flows, assuming
other factors are held constant. We currently do not have any interest rate hedging arrangements with respect to our
credit facility, nor are any contemplated in the future. A significant increase in prevailing interest rates that results in a
substantial increase in the interest rates applicable to our indebtedness could substantially increase our interest expense
and have a material adverse effect on our financial condition and results of operations.
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Restrictive covenants may adversely affect our operations.
Our credit facility and the indenture governing the Senior Notes contain a number of restrictive covenants that
impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our
long-term best interest, including our ability, among other things, to:
•
•
•
•
incur or assume additional debt or provide guarantees in respect of obligations of other persons;
issue redeemable stock and preferred stock;
pay dividends or distributions or redeem or repurchase capital stock;
prepay, redeem or repurchase certain debt;
• make loans and investments;
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•
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create or incur liens;
restrict distributions from our subsidiaries;
sell assets and capital stock of our subsidiaries;
consolidate or merge with or into another entity, or sell all or substantially all of our assets; and
enter into new lines of business.
A breach of the covenants under the indentures governing the Senior Notes or under our credit facility could
result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate
the related debt and may result in an acceleration of any other debt that contains a cross-acceleration or cross-default
provision. In addition, an event of default under our credit facility would permit the lenders under the facility to
terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our
credit facility could proceed against the collateral granted to them to secure that debt.
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate
our business, remain in compliance with debt covenants and make payments on our debt.
The aggregate amount of our outstanding indebtedness could have important consequences for us, including the
following:
•
•
any failure to comply with the obligations of any of our debt agreements, including financial and other
restrictive covenants, could result in an event of default under the agreements governing such indebtedness;
the covenants contained in our debt agreements limit our ability to borrow money in the future for
acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations
and may limit our flexibility in operating our business;
• we may have a higher level of debt than some of our competitors, which may put us at a competitive
disadvantage;
• we may be more vulnerable to economic downturns and adverse developments in our industry or the
economy in general, especially extended or further declines in oil and natural gas prices; and
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•
our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the
industry in which we operate.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be
affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these
factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from
operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we
do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets,
borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise
equity on terms acceptable to us, if at all.
If commodity prices continue to drop, we may be limited or unable to lawfully declare and pay dividends on our
capital stock.
The Delaware General Corporation Law (the “DGCL”) permits payment of dividends out of a corporation’s
surplus. Surplus is defined as the excess of net assets (total assets less total liabilities) over a corporation’s capital as
determined under the DGCL. If commodity prices continue to decline, the value of our net assets will also continue to
decline and, accordingly, our ability to lawfully declare and pay dividends may also decline.
The present value of future net revenues from our estimated proved reserves is not necessarily the same as the current
market value of our estimated proved oil, natural gas and NGL reserves.
The present value of future net revenues from our estimated proved reserves is not necessarily the same as the
current market value of our estimated proved oil, natural gas and NGL reserves. We base the estimated discounted future
net cash flows from our estimated proved reserves on the unweighted arithmetic average of the first-day-of-the-month
prices for each month within the 12-month period prior to the end of the reporting period and costs in effect as of the
date of the estimate. However, actual future net cash flows from our oil, natural gas and NGL properties also will be
affected by factors such as:
•
•
•
•
•
•
the actual prices we receive for oil, natural gas and NGLs;
our actual operating costs in producing oil, natural gas and NGLs;
the amount and timing of actual production;
the amount and timing of our capital expenditures;
the supply of and demand for oil, natural gas and NGLs; 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 of actual future net cash flows from our estimated
reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted
future net cash flows in compliance with ASC Topic 932, Extractive Activities—Oil and Natural Gas, may not be the
most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil
and natural gas industry in general.
We have limited experience drilling wells on our TMS acreage, which has a short operational history and is subject to
more uncertainties than our drilling program in more established formations.
We and other operators have begun drilling wells in the TMS only recently. Accordingly, there is limited
information on which we can determine optimum drilling and completion strategies and drilling costs (which may be
higher than other trends in which we operate), or estimate production decline rates or recoverable reserves from drilling
on our acreage in this trend. Our drilling plans with respect to the TMS are flexible and depend on a number of factors,
including the extent to which our initial wells in the trend are commercially successful.
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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the
completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into
subsurface formations to stimulate natural gas and, to a lesser extent, oil production. The federal Safe Drinking Water
Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC,
Program. However, hydraulic fracturing is generally exempt from regulation under the UIC Program, and thus the
process is typically regulated by state agencies. Nevertheless, the EPA has asserted federal regulatory authority over
hydraulic fracturing involving diesel additives under the UIC Program. On February 12, 2014, the EPA published
revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance
document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and
natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the
hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas,
Louisiana and Mississippi, where we maintain acreage, the EPA is encouraging state programs to review and consider
use of the above-mentioned guidance. Furthermore, legislation to amend the SDWA to repeal the exemption for
hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control
of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids
used in the fracturing process, have been proposed in recent sessions of Congress.
On May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its
intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information
related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. The
EPA plans to develop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed
mechanism – regulatory, voluntary, or a combination of both – to collect data on hydraulic fracturing chemical
substances and mixtures.
Although not presently relevant to our business since we do not currently maintain acreage on federal or Indian
lands, on March 26, 2015, the BLM published a final rule governing hydraulic fracturing on federal and Indian lands.
The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing
program, management of recovered fluids, and submission to BLM of detailed information about the proposed operation,
including wellbore geology, the location of faults and fractures, and the depths of all usable water. The rule took effect
on June 24, 2015, although it is the subject of several pending lawsuits filed by industry groups and at least four states,
alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. On September 30, 2015, the
United States District Court for Wyoming issued a preliminary injunction preventing BLM from implementing the rule
nationwide. This order has been appealed to the Tenth Circuit Court of Appeals.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on
environmental aspects of hydraulic fracturing practices. For example, the EPA has commenced a study of the potential
adverse effects that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released its
draft assessment report for peer review and public comment, finding that, while there are certain mechanisms by which
hydraulic fracturing activities could potentially impact drinking water resources, there is no evidence available showing
that those mechanisms have led to widespread, systemic impacts. Also, on February 6, 2015, the EPA released a report
with findings and recommendations related to public concern about induced seismic activity from disposal wells. The
report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events.
Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S.
Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing.
These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained,
could spur initiatives to further regulate hydraulic fracturing or the disposal of produced water and flowback fluid in
underground injection wells under the SDWA or other regulatory mechanism. Also, some states have adopted, and other
states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise
require the public disclosure of chemicals used in the hydraulic fracturing process. For example, in December 2011, the
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Commission adopted rules and regulations requiring that hydraulic fracturing well operators disclose the list of chemical
ingredients subject to the requirements of Occupational Safety and Health Act, as amended, or OSHA, to state regulators
and the public. Also, in May 2013, the Commission adopted new rules governing well casing, cementing and other
standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules
took effect in January 2014. Additionally, on October 28, 2014, the Commission adopted disposal well rule amendments
designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced
water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey.
The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a
proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also
clarify the Commission's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a
disposal well is likely to contribute to seismic activity. The Commission has used this authority to deny permits for waste
disposal sites.
These or any other new laws or regulations that significantly restrict hydraulic fracturing or the disposal of
produced water and flowback fluid in underground injection wells could make it more difficult or costly for us to drill
and produce from conventional or tight formations, increase our costs of compliance and doing business and make it
easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings.
In addition, on August 16, 2012, the EPA published final rules that subject oil and natural gas production,
processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS,
and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS for
completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from
compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The
final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or
"green completions" on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA
received numerous requests for reconsideration of these rules from both industry and the environmental community. In
response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for
reconsideration. For example, in September 2013 and December 2014, the EPA amended its rules to extend compliance
deadlines and to clarify the NSPS. Further, on July 31, 2015, the EPA finalized two updates to the NSPS to address the
definition of low-pressure wells and references to tanks that are connected to one another (referred to as connected in
parallel). In addition, on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and VOC
emissions from oil and gas industry, including new “downstream” requirements covering equipment in the natural gas
transmission segment of the industry that was not regulated by the 2012 rules. The public comment period closed on
December 4, 2015.
Also, on January 22, 2016, the BLM announced a proposed rule to reduce the flaring, venting and leaking of
methane from oil and gas operations on federal and Indian lands. The proposed rule would require operators to use
currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and
replace outdated equipment that vents large quantities of gas into the air. The rule would also clarify when operators owe
the government royalties for flared gas.
Further federal, state and/or local laws governing hydraulic fracturing could result in additional permitting and
financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and
recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential
increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the
consequences of failure to comply by us could have a material adverse effect on our business, financial condition and
results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if
additional federal, state and/or local laws are enacted.
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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. In addition, the third parties on whom we rely on for gathering
and transportation services are also subject to complex federal, state and other laws that could adversely affect the
cost, manner or feasibility of conducting our business.
Our oil and natural gas development and production operations are subject to complex and stringent laws and
regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain
numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may
incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of
compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations
become applicable to our operations. Failure to comply with such laws and regulations, as interpreted and enforced,
could have a material adverse effect on our business, financial condition and results of operations. Please read “Item 1.
Business—Environmental Matters and Regulation” for a description of the laws and regulations that affect us.
In addition, the operations of the third parties on whom we rely for gathering and transportation services are
also subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits,
approvals and certifications from various federal, state and local government authorities. These third parties may incur
substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such
third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations,
these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and
regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition
and results of operations. Please read “Item 1. Business—Environmental Matters and Regulation” for a description of the
laws and regulations that affect the third parties on whom we rely.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased
operating costs and reduced demand for the oil and natural gas that we produce.
On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the CAA definition of
"pollutant" includes carbon dioxide and other GHGs and, therefore, the EPA has the authority to regulate carbon dioxide
emissions from automobiles. Thereafter, on December 15, 2009, the EPA published its findings that GHG emissions
present an endangerment to public health and the environment because emissions of such gases are, according to the
EPA, contributing to the warming of the earth's atmosphere and other climate changes. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In
response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of
GHG emissions under the CAA. The motor vehicle rule, which became effective in July 2010, purports to limit
emissions of GHGs from motor vehicles. The EPA adopted the Tailoring Rule in May 2010, and it became effective in
January 2011. The Tailoring Rule established new GHG emissions thresholds that determine when stationary sources
must obtain permits under the PSD and Title V programs of the CAA. On June 23, 2014, the Supreme Court held that
stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The
Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at
sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memorandums
providing initial guidance on GHG permitting requirements in response to the Court's decision in Utility Air Regulatory
Group v. EPA. In its preliminary guidance, the EPA indicates it will undertake a rulemaking action to rescind any PSD
permits issued under the portions of the Tailoring Rule that were vacated by the Court. In the interim, the EPA issued a
narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of
the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title
V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued
under the invalid regulations.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large
GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution
companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule
expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage
and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with
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reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule
to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells
using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
In addition, the EPA has continued to adopt GHG regulations of other industries, such as its August 2015
adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final
Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon
dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission
guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as
industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals.
In addition, the U.S. Congress has from time to time considered legislation to reduce the 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. Most of these cap and
trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender
emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG
emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of
allowances is expected to escalate significantly. Furthermore, some states have enacted renewable portfolio standards,
which require utilities to purchase a certain percentage of their energy from renewable fuel sources. Although the U.S.
Congress has not adopted comprehensive GHG legislation at this time, it may do so in the future, and many states
continue to pursue regulations to reduce GHG emissions.
Furthermore, in December 2015, the United States joined the international community at the 21st Conference of
the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting
Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to
conserve and enhance sinks and reservoirs of GHGs. The Agreement, if ratified, establishes a framework for the parties
to cooperate and report actions to reduce GHG emissions.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The
adoption of any legislation or regulations that otherwise limit emissions of GHGs from our equipment and operations
could require us to incur increased operating costs, such as costs to monitor and report GHG emissions, purchase and
operate emissions control systems to reduce emissions of GHGs associated with our operations, acquire emissions
allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs
applicable to power plants or refineries could also increase the cost of consuming, and thus could adversely affect
demand for the oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG
emissions could have an adverse effect on our business, financial condition and results of operations. Please read
"Item 1. Business—Environmental Matters and Regulation."
Our operations are subject to environmental and operational safety laws and regulations that may expose us to
significant costs and liabilities.
We may incur significant delays, costs and liabilities as a result of stringent and complex environmental, health
and safety requirements applicable to our oil and natural gas development and production operations. These laws and
regulations may impose numerous obligations applicable to our operations, including that they may (i) require the
acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and
concentration of various substances that can be released into the environment or injected into formations in connection
with oil and natural gas drilling, production and transportation activities; (iii) govern the sourcing and disposal of water
used in the drilling and completion process; (iv) limit or prohibit drilling or injection activities on certain lands lying
within wilderness, wetlands, seismically active areas, and other protected areas; (v) require remedial measures to
mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;
(vi) result in the suspension or revocation of necessary permits, licenses and authorizations; (vii) impose substantial
liabilities for pollution resulting from drilling and production operations; and (viii) require that additional pollution
controls be installed. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power
to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and
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costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment
of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations,
the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution
controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations.
In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt
our operations and limit our growth and revenue. These laws and regulations are complex, change frequently and have
tended to become increasingly stringent over time.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our
operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater
discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under
certain environmental laws and regulations, we could be subject to strict and joint and several liability for the removal or
remediation of previously released materials or property contamination regardless of whether we were responsible for
the release or contamination or the operations were in compliance with all applicable laws at the time those actions were
taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our
petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions
to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for
personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose
us to significant liabilities that could have a material adverse effect on our business, financial condition and results of
operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more
stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make
significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our
competitive position, business, financial condition and results of operations. We may not be able to recover some or any
of these costs from insurance. Please read “Item 1. Business—Environmental Matters and Regulation” for more
information.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks
associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, provides
for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates
that the Commodity Futures Trading Commission, or the CFTC, the SEC and certain federal regulators of financial
institutions, or Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing
definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires
clearing and trade execution practices for certain market participants and may result in certain market participants
needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the
SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we
refer to as the "Mandatory Clearing Rule," requiring clearing of hedges, or swaps, that are subject to it (currently, only
certain interest rate and credit default swaps, which we do not presently have), a rule, which we refer to as the "End User
Exception,” establishing an "end user" exception to the Mandatory Clearing Rule, a rule, which we refer to as the
“Margin Rule,” setting forth collateral requirements in connection with swaps that are not cleared and also an exception
to the Margin Rule for end users that are not financial end users, which exception we refer to as the “Non-Financial End
User Exception,” and a rule, subsequently vacated by the United States District Court for the District of Columbia and
remanded to the CFTC for further proceedings, imposing position limits. The CFTC proposed a new version of this rule,
which we refer to as the "Re-Proposed Position Limit Rule," with respect to which the comment period has closed but a
final rule has not been issued.
We qualify for the End User Exception and will utilize it if the Mandatory Clearing Rule is expanded to cover
swaps in which we participate, we qualify for the Non-Financial End User Exception and will not be required to post
margin under the Margin Rule and the quantities under the swaps in which we participate are well within applicable
limits under the Re-Proposed Position Limit Rule, so we do not expect to be directly affected by any of such rules.
However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their
50
hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in
connection with their hedging activities with other swap dealers, major swap participants, financial end users and other
persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-
U.S. jurisdictions have enacted laws and regulations, which we refer to collectively as “Foreign Regulations” which may
apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which
have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule is ultimately effected,
such proposed rule could significantly increase the cost of our derivative contracts, materially alter the terms of our
derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that
we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts, and increase
our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our
use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign Regulations, our results of operations
may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan
for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and
natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related
to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and
regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our
financial condition, and our results of operations.
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax
deductions currently available with respect to oil and natural gas exploration and production are eliminated as a
result of future legislation.
Legislation is proposed from time to time that contains proposals to eliminate certain key U.S. federal income
tax preferences currently available to oil and natural gas exploration and production companies. These proposals include,
but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the
elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for
certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical
expenditures. It is unclear whether any of the foregoing proposals will actually be enacted or how soon any such changes
in law could become effective. The passage of any legislation as a result of these proposals or any other similar change in
U.S. federal income tax law could eliminate and/or defer certain tax deductions that are currently available with respect
to oil and natural gas exploration and production. Any such change could materially adversely affect our business,
financial condition and results of operations by increasing the after-tax costs we incur which would in turn make it
uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and
decreases in production and reserves.
We are subject to anti-takeover provisions in our restated certificate of incorporation and amended and restated
bylaws, our Rights Plan and Delaware law that could delay or prevent an acquisition of our company, even if the
acquisition would be beneficial to our stockholders.
Provisions in our restated certificate of incorporation and amended and restated bylaws may delay or prevent an
acquisition of us. These provisions may also frustrate or prevent any attempts by our stockholders to replace or remove
our current management by making it more difficult for stockholders to replace members of our board of directors, who
are responsible for appointing the members of our management team. Furthermore, because we are incorporated in
Delaware, we are governed by the provisions of Section 203 of the DGCL, which prohibits, with some exceptions,
stockholders owning in excess of 15% of our outstanding voting stock from merging or combining with us. In addition,
the Company entered into the Rights Plan on July 28, 2015. The Rights Plan is designed to preserve stockholder value
and the value of our NOLs by acting as a deterrent to any person acquiring beneficial ownership of 4.9% or more of the
Company’s outstanding common stock without the approval of our board of directors. Although not intended for this
purpose, the Rights Plan has an anti-takeover effect. Finally, our amended and restated bylaws establish advance notice
requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at
stockholder meetings. Although we believe these provisions together provide an opportunity to receive higher bids by
requiring potential acquirers to negotiate with our board of directors, they would apply even if an offer to acquire us may
be considered beneficial by some stockholders.
51
We are subject to legal proceedings and legal compliance risks.
We, including our officers and directors, are involved in various legal proceedings from time to time. Certain of
these legal proceedings may be a significant distraction to management and could expose our Company to significant
liability, including damages, fines, penalties and attorneys’ fees and costs, any of which could have a material adverse
effect on our business and results of operations.
We discuss the risks and uncertainties related to our litigation in more detail below in “Item 3. Legal
Proceedings” and in Note 14, “Commitments and Contingencies.”
The requirements of being a public company, including compliance with the reporting requirements of the Securities
Exchange Act of 1934, as amended, and the requirements of the Sarbanes-Oxley Act, may strain our resources,
increase our costs and distract management, and we may be unable to comply with these requirements in a timely or
cost-effective manner.
We are required to comply with laws, regulations and requirements, including the reporting obligations of the
Exchange Act, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”),
related regulations of the SEC and the requirements of the NYSE with which we were not required to comply as a
private company. Complying with these statutes, regulations and requirements requires a significant amount of time from
our board of directors and management and has significantly increased our legal and financial compliance costs and
made such compliance more time-consuming and costly. As compared to a private company, among other things, we are
required to:
• maintain a more comprehensive compliance function;
•
•
•
design, evaluate and maintain a system of internal controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC
and the Public Company Accounting Oversight Board;
comply with rules promulgated by the NYSE;
prepare and distribute periodic public reports in compliance with our obligations under the federal
securities laws;
• maintain internal policies, such as those relating to disclosure controls and procedures and insider trading;
•
involve and retain to a greater degree outside counsel and accountants in the above activities; and
• maintain an investor relations function.
In addition, as a public company subject to these rules and regulations, it may become more difficult and
expensive for us to obtain director and officer liability insurance, and we may be required to accept greater coverage than
we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract
and retain qualified executive officers and qualified members to serve on our board of directors, particularly the audit
committee of the board of directors (the “Audit Committee”).
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 and comply with the certification and
reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not
enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate
material weaknesses or significant deficiencies and to develop or maintain effective controls, or any difficulties
encountered in our implementation or improvement of our internal controls over financial reporting could result in
material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to
sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also
cause investors to lose confidence in our reported financial information.
52
We may have potential business conflicts of interest with members of the Sanchez Group regarding our past, ongoing
and future relationships and the resolution of these conflicts may not be favorable to us.
Conflicts of interest may arise between members of the Sanchez Group and us in a number of areas relating to
our past, ongoing and future relationships, including:
•
•
•
•
labor, tax, employee benefit, indemnification and other matters arising under agreements with SOG;
employee recruiting and retention;
business opportunities that may be attractive to both members of the Sanchez Group and us; and
business transactions that we enter into with members of the Sanchez Group.
We may not be able to resolve any potential conflicts, and, even if we do so, the resolution may be less
favorable to us than if we were dealing with an unaffiliated party.
Finally, in connection with our initial public offering (“IPO”), we entered into several agreements with
members of the Sanchez Group. These agreements were made in the context of a related party transaction. The terms of
these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties.
Pursuant to the terms of our restated certificate of incorporation, members of the Sanchez Group are not required to
offer corporate opportunities to us, and our directors and officers may be permitted to offer certain corporate
opportunities to members of the Sanchez Group before us.
Our board of directors includes persons who are also directors and/or officers of members of the Sanchez
Group. Our restated certificate of incorporation provides that:
• members of the Sanchez Group are free to compete with us in any activity or line of business;
• we do not have any interest or expectancy in any business opportunity, transaction, or other matter in which
members of the Sanchez Group engage or seek to engage merely because we engage in the same or similar
lines of business;
•
•
to the fullest extent permitted by law, members of the Sanchez Group will have no duty to communicate
their knowledge of, or offer, any potential business opportunity, transaction, or other matter to us, and
members of the Sanchez Group are free to pursue or acquire such business opportunity, transaction, or
other matter for themselves or direct the business opportunity, transaction, or other matter to its affiliates;
and
if any director or officer of any member of the Sanchez Group who is also one of our officers or directors
becomes aware of a potential business opportunity, transaction, or other matter (other than one expressly
offered to that director or officer in writing solely in his or her capacity as our director or officer), that
director or officer will have no duty to communicate or offer that business opportunity to us, and will be
permitted to communicate or offer that business opportunity to such member of the Sanchez Group and that
director or officer will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted
in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the business
opportunity or (2) acted in bad faith or in a manner inconsistent with our best interests or those of our
stockholders.
53
We depend on SOG to provide us with certain services for our business. The services that SOG provides to us may not
be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay
increased costs to replace these services after our agreements with SOG expire.
Certain services required by us for the operation of our business, including general and administrative services,
geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational
services, information technology services, compliance, insurance maintenance and management of outside professionals,
are provided by SOG pursuant to the Services Agreement. The services provided under the Services Agreement
commenced on the date that the IPO closed and will terminate five years thereafter. The term automatically extends for
additional 12-month periods and is terminable by either party at any time upon 180 days’ written notice. See “Corporate
Governance—Compensation Committee” in the proxy statement for the 2016 annual meeting of stockholders, which is
incorporated by reference to this report. While these services are being provided to us by SOG, our operational flexibility
to modify or implement changes with respect to such services or the amounts we pay for them is limited. After the
expiration or termination of this agreement, we may not be able to replace these services or enter into appropriate
third-party agreements on terms and conditions, including cost, comparable to those that we will receive from SOG
under our agreements with SOG.
In addition, SOG may outsource some or all of these services to third parties, and a failure of all or part of
SOG’s relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance
on SOG and others as service providers and on SOG’s outsourcing relationships, and our limited ability to control certain
costs, could have a material adverse effect on our business, financial condition and results of operations.
A portion of our total outstanding shares is held by members of the Sanchez Group and may be sold into the market
at any time. This could cause the market price of our common stock to drop significantly, even if our business is
doing well.
As of December 31, 2015, members of the Sanchez Group owned, in the aggregate, approximately 11% of our
outstanding common stock. These shares are eligible for resale in the public markets, subject to the volume, manner of
sale and other limitations under Rule 144 of the Securities Act. In addition, under certain circumstances, these persons
have the right to require us to register the resale of their shares. Moreover, we have registered all of the shares of our
common stock that we may issue under our employee benefit plans. These shares can be freely sold in the public market
upon issuance unless, pursuant to their terms, these stock awards have transfer restrictions attached to them. Sales of a
substantial number of shares of our common stock, or the perception in the market that the holders of a large number of
shares intend to sell shares, could reduce the market price of our common stock.
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
The information required by this Item is set forth in Note 14, “Commitments and Contingencies.”
Item 4. Mine Safety Disclosures
Not applicable.
54
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Market for Registrant’s Common Equity. Shares of our common stock are traded on the NYSE under the
symbol “SN.” The following table sets forth the reported high and low closing prices of our common stock for the
periods indicated:
2015:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2014:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Common Stock
High
Low
15.97
15.64
9.33
8.08
$
$
$
$
7.97
9.62
5.30
3.64
Common Stock
High
Low
31.98
38.13
36.92
25.20
$
$
$
$
23.85
25.98
26.26
6.48
$
$
$
$
$
$
$
$
On February 26, 2016, the last sale price of our common stock, as reported on the NYSE, was $3.32 per share.
Holders. The number of shareholders of record of our common stock was approximately 38 on February 26,
2016, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank.
Dividends. We pay dividends quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when and
if declared by the Company’s board of directors on our Series A and Series B Convertible Perpetual Preferred Stock in
the amounts of 4.875% and 6.50%, respectively. As of December 31, 2015, we have paid approximately $52.9 million in
dividends to holders of our Series A and Series B Convertible Perpetual Preferred Stock since their respective issuances.
We have not paid any cash dividends on our common equity since our inception. Although our future dividend
policy is within the discretion of our board of directors and will depend upon various factors, including our results of
operations, financial condition, capital requirements and investment opportunities, we do not anticipate declaring or
paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future
earnings to finance current operations and the future expansion of our business.
Securities Authorized for Issuance Under Equity Compensation Plans. The following table sets forth certain
information as of December 31, 2015 regarding the Sanchez Energy Corporation Second Amended and Restated 2011
Long Term Incentive Plan (the “LTIP”). The LTIP was approved by our stockholders on May 21, 2015, which increased
55
the number of the shares of our common stock available for incentive awards pursuant to the LTIP’s predecessor, which
was approved by our stockholders in 2012.
(a)
(b)
Number of Securities to be Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights Reflected in Column (a))
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
(c)
Number of Securities
Remaining Available
For Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Plan Category:
Equity Compensation Plans Approved by
Stockholders
Equity Compensation Plans Not Approved
by Stockholders
Total
—
N/A
—
N/A
N/A
—
5,242,056 (1)
N/A
5,242,056
(1) The maximum number of shares that may be delivered pursuant to the LTIP is limited to (i) 4,000,000 shares of
common stock plus the number of shares of common stock available under the predecessor to the LTIP on the record
date of the 2015 Annual Meeting (the "Record Date") at which the stockholders approved the LTIP as well as (ii)
upon the issuance of additional shares of common stock from time to time after the Record Date, an automatic
increase of 15% of such issuance of additional shares of common stock, unless our board of directors determines to
increase the maximum number of shares of common stock by a lesser amount.
Recent Sales of Unregistered Securities. All sales of unregistered securities within the last fiscal year have been
previously reported in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K.
Repurchases of Equity Securities. Neither we nor any “affiliated purchaser” repurchased any of our equity
securities in the quarter ended December 31, 2015.
Comparative Stock Performance
The performance graph below compares the cumulative total stockholder return for our common stock to that of
the Standard and Poor’s, or S&P, the S&P 500 Index and the S&P 500 Oil & Gas Exploration and Production Index for
the period indicated as prescribed by SEC rules. “Cumulative total return” means the change in share price during the
measurement period divided by the share price at the beginning of the measurement period. The graph assumes $100 was
invested on December 19, 2011 (the date on which our common stock began regular way trading on the NYSE) in each
of our common stock, the S&P 500 Index and the S&P 500 Oil & Gas Exploration and Production Index.
56
COMPARISON OF CUMULATIVE TOTAL RETURN
AMONG SANCHEZ ENERGY CORPORATION, THE S&P 500 INDEX,
AND THE S&P 500 OIL & GAS EXPLORATION AND PRODUCTION INDEX
Note: The stock price performance of our common stock is not necessarily indicative of future performance.
The above information under the caption “Comparative Stock Performance” shall not be deemed to be
“soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any
future filing under the Securities Act or the Exchange Act except to the extent that we specifically request that such
information be treated as “soliciting material” or specifically incorporate such information by reference into such a
filing.
Item 6. Selected Financial Data
The selected financial data table below shows our historical consolidated financial data as of and for each of the
five years in the period ended December 31, 2015. The selected financial data is derived from our audited historical
financial statements.
Our historical financial statements prior to December 19, 2011 have been prepared on a carve-out basis from the
accounts of SEP I. The carved-out financial information includes all assets, liabilities and results of operations of the
unconventional oil and natural gas properties and related assets contributed to us by SEP I for the periods prior to
December 19, 2011.
Our historical financial statements prior to December 19, 2011 included in this Annual Report on Form 10-K
may not necessarily reflect our financial position, results of operations, and cash flows as if we had operated as a
stand-alone public company during those periods. The historical financial data prior to December 19, 2011 reflect
historical accounts attributable to the SEP I assets (the “SEP I Assets”) on a “carve-out” basis, including allocated
overhead from our predecessor in interest, for periods prior to our acquisition of the SEP I Assets on December 19, 2011
and do not reflect any estimate of additional overhead that we may incur as a separate company.
57
The selected financial data should be read together with “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” included in
this Annual Report on Form 10-K.
Year Ended December 31,
2015
2014
2013
2012
2011
(in thousands, except per share amounts)
REVENUES:
Oil sales
Natural gas liquids sales
Natural gas sales
Total revenues
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses
Production and ad valorem taxes
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
General and administrative (1)
Total operating costs and expenses
Operating income (loss)
Other income (expense):
Interest and other income (expense)
Interest expense
Net gains (losses) on commodity derivatives
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Less:
Preferred stock dividends
Net income allocable to participating securities(2)(3)
Net income (loss) attributable to common
$
307,971 $ 538,887 $ 290,322 $ 42,377 $ 13,905
22
589
14,516
66,989
60,188
666,064
13,013
11,085
314,420
69,011
98,797
475,779
15
766
43,158
156,528
26,870
344,572
1,365,000
74,160
1,967,130
(1,491,351)
93,581
37,787
338,097
213,821
63,692
746,978
(80,914)
35,669
17,334
134,845
—
47,951
235,799
78,621
3,401
2,124
15,922
—
37,239
58,686
(15,528)
1,628
830
4,252
—
5,368
12,078
2,438
(2,163)
(126,399)
172,886
44,324
(1,447,027)
7,600
(1,454,627)
289
(89,800)
137,205
47,694
(33,220)
(11,429)
(21,791)
135
(30,934)
(16,938)
(47,737)
30,884
3,986
26,898
74
(99)
(742)
(767)
(16,295)
—
(16,295)
10
—
(480)
(470)
1,968
—
1,968
(16,008)
—
(33,590)
—
(18,525)
(364)
(2,112)
—
—
—
stockholders
$ (1,470,635) $ (55,381) $
8,009 $ (18,407) $ 1,968
Net income (loss) per common share - basic and
diluted
$
(25.70) $
(1.06) $
0.22 $
(0.56) $
0.09
Weighted average number of shares used to calculate
net income (loss) attributable to common
stockholders - basic and diluted (4)
57,229
52,338
36,379
33,000
22,479
(1) Includes stock based compensation expense of $14.8 million, $12.8 million, $17.8 million and $25.5 million for the
years ended December 31, 2015, 2014, 2013 and 2012, respectively. Also includes acquisition and divestiture costs
of $3.8 million, $1.8 million and $4.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.
(2) The Company’s restricted shares of common stock are participating securities.
(3) For the years ended December 31, 2015, 2014 and 2012 no losses were allocated to participating restricted stock
because such securities do not have a contractual obligation to share in the Company’s losses. There were no
outstanding shares of participating restricted stock for the year ended December 31, 2011.
(4) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314
shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Stock and
Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these
shares were anti-dilutive. The year ended December 31, 2014 excludes 1,732,888 shares of weighted average
restricted stock and 13,527,738 shares of common stock resulting from an assumed conversion of the Company’s
58
Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the
calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The year
ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of
common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred
Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted
earnings per common share as these shares were anti-dilutive. The year ended December 31, 2012 excludes 184,230
shares of weighted average restricted stock and 1,992,857 shares of common stock resulting from an assumed
conversion of the Company’s Series A Convertible Perpetual Preferred Stock from the calculation of the
denominator for diluted earnings per common share as these shares were anti-dilutive. The Company had no
outstanding stock awards prior to its initial grants in January 2012.
As of December 31,
2015
2014
2013
2012
2011
(in thousands)
Balance Sheet Data:
Working capital (1)
Total assets (1)
Long term debt, net of premium and discount
Total stockholders' equity (deficit) / parent net investment
54,061 $ 15,671 $ 63,890
$ 499,112 $ 412,798 $
$ 1,542,343 $ 3,042,168 $ 1,622,271 $ 426,574 $ 217,356
—
$ 1,746,966 $ 1,746,263 $ 593,258 $
$ (456,169) $ 999,587 $ 857,309 $ 366,743 $ 215,141
— $
(1) As a result of the early adoption of ASU 2015-17 on a retrospective basis as of the quarter ended December 31,
2015, the current deferred tax liability as of December 31, 2014 was reduced by approximately $33.2 million,
and the current deferred tax asset as of December 31, 2013 was reduced by approximately $6.8 million. These
retrospective changes are reflected in the working capital and total assets amounts in the table above. See
further discussion on the early adoption of ASU 2015-17 in Note 8, "Income Taxes."
Year Ended December 31,
2015
2014
2013
(in thousands)
2012
2011
$ 272,024 $
415,335 $
189,261 $
29,072 $
5,546
$
(294,331) $
(1,361,264) $
(1,093,363) $
(181,427) $
(108,005)
$ (16,359) $ 1,266,112 $ 1,007,286 $ 139,661 $ 165,500
Cash Flow Data:
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing
activities
Non-GAAP Financial Measures
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss):
• Plus:
•
Interest expense, including net losses (gains) on interest rate derivative contracts;
• Net losses (gains) on commodity derivative contracts;
• Net settlements received (paid) on commodity derivative contracts;
• Depreciation, depletion, and amortization and accretion;
• Stock-based compensation expense;
59
• Acquisition and divestiture costs included in general and administrative;
•
Income tax expense (benefit);
• Loss (gain) on sale of oil and natural gas properties;
•
Impairment of oil and natural gas properties; and
• Other non-recurring items that we deem appropriate.
• Less:
• Premiums on commodity derivative contracts;
• Amortization of deferred gain on Western Catarina Midstream Divestiture;
•
Interest income; and
• Other non-recurring items that we deem appropriate.
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our
financial statements, such as investors, commercial banks and others, to assess:
•
•
our operating performance as compared to that of other companies and companies in our industry, without
regard to financing methods, capital structure or historical cost basis; and
our ability to incur and service debt and fund capital expenditures.
Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss),
cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented
in accordance with U.S. GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another
company because all companies may not calculate Adjusted EBITDA in the same manner.
The following table presents a reconciliation of our net income (loss) to Adjusted EBITDA (in thousands):
Net income (loss)
Plus:
2015
$ (1,454,627) $ (21,791) $
Year Ended December 31,
2013
2014
26,898 $ (16,295) $
2012
Interest expense
Net losses (gains) on commodity derivative contracts
Net settlements received (paid) on commodity derivative contracts
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
Stock-based compensation expense
Acquisition and divestiture costs included in general and administrative
Write off of joint venture receivable, non-recurring
Income tax expense (benefit)
126,399
(172,886)
142,468
344,572
1,365,000
14,831
3,814
2,251
7,600
89,800
(137,205)
5,600
338,097
213,821
12,843
1,808
—
(11,429)
30,934
16,938
(5,787)
134,845
—
17,751
4,129
—
3,986
Less:
Amortization of deferred gain on Western Catarina Midstream Divestiture
Premiums on commodity derivative contracts(1)
Interest income
(3,086)
—
(443)
—
(718)
(193)
—
(2,838)
(190)
99
742
2,749
15,922
—
25,542
—
—
—
—
(3,059)
(74)
2011
1,968
—
480
—
4,252
—
—
—
—
—
—
—
(1)
Adjusted EBITDA
$
375,893 $ 490,633
$ 226,666 $
25,626 $
6,699
60
(1) This amount includes premiums accrued but not paid as of the end of the period.
The following table presents a reconciliation of net cash provided by (used in) operating activities to Adjusted
EBITDA (in thousands):
Year Ended December 31,
Net cash provided by operating activities
Net change in operating assets and liabilities
Cash reimbursements received for operating leasehold improvements
Interest expense, net (1)
Settlements on commodity derivative contracts, non-cash
Income tax expense
Write off of joint venture receivable, non-cash
Acquisition and divestiture costs included in general and administrative
Loss on investment in SPP
2015
2014
$ 272,025 $ 415,335 $ 189,261 $
2013
(27,961)
(2,648)
117,723
11,466
158
2,251
3,814
(935)
(6,238)
—
79,850
(122)
—
—
1,808
—
12,334
—
23,584
(2,642)
—
—
4,129
—
Adjusted EBITDA
$ 375,893 $ 490,633 $ 226,666 $
2012
29,072 $
(3,806)
—
(74)
434
—
—
—
—
25,626 $
2011
5,546
1,154
—
(1)
—
—
—
—
—
6,699
(1) This amount includes cash interest expense on our Senior Notes and credit agreements, net of interest income.
Adjusted Net Income (Loss)
We present adjusted net income (loss) attributable to common stockholders (“Adjusted Net Income (Loss)”), in
addition to our reported net income (loss) in accordance with U.S. GAAP. This information is provided because
management believes exclusion of the impact of the items included in our definition of Adjusted Net Income (Loss)
below will help investors compare results between periods, identify operating trends that could otherwise be masked by
these items and highlight the impact that commodity price volatility has on our results. We define Adjusted Net Income
(Loss) as net income (loss):
Plus:
• Non-cash preferred stock dividends associated with conversion;
• Net losses (gains) on commodity derivative contracts;
• Net settlements received (paid) on commodity derivative contracts;
• Stock-based compensation expense;
• Acquisition and divestiture costs included in general and administrative;
•
Impairment of oil and natural gas properties;
• Other non-recurring items that we deem appropriate; and
• Tax impact of adjustments to net income (loss).
61
Less:
• Premiums on commodity derivative contracts;
• Amortization of deferred gain on Western Catarina Midstream Divestiture;
• Preferred stock dividends; and
• Other non-recurring items that we deem appropriate.
The following table presents a reconciliation of our net income (loss) to Adjusted Net Income (Loss) (in
thousands, except per share data):
Net income (loss)
Less: Preferred stock dividends
Net income (loss) attributable to common shares and participating securities
Plus:
$ (1,454,627) $ (21,791) $ 26,898 $ (16,295) $ 1,968
—
1,968
(16,008)
(1,470,635)
(2,112)
(18,407)
(18,525)
8,373
(33,590)
(55,381)
2015
Year Ended December 31,
2014
2013
2012
2011
Non-cash preferred stock dividends associated with conversion
Non-cash write off of joint venture receivables
Net losses (gains) on commodity derivatives contracts
Net settlements received (paid) on commodity derivative contracts
Premiums on commodity derivative contracts (1)
Impairment of oil and natural gas properties
Stock-based compensation expense
Acquisition and divestiture costs included in general and administrative
Amortization of deferred gain on Western Catarina Midstream Divestiture
Tax impact of adjustments to net income (loss) (2)
Adjusted net income (loss)
Adjusted net income allocable to participating securities(3)(4)
48
2,251
(172,886)
142,468
—
1,365,000
14,831
3,814
(3,086)
12,385
(105,810)
—
Adjusted net income (loss) attributable to common stockholders
$
(105,810) $
17,297
—
(137,205)
5,600
(718)
213,821
12,843
1,808
—
(33,081)
24,984
(1,157)
23,827 $ 33,155 $
—
—
16,938
(5,787)
(2,838)
—
17,751
4,129
—
(3,898)
34,668
(1,513)
—
—
—
—
480
742
—
2,749
—
(3,059)
—
—
—
25,542
—
—
—
—
—
—
2,448
7,567
—
(221)
7,346 $ 2,448
Adjusted net income (loss) per common share - basic and diluted(5)(6)(7)(8)
$
(1.85) $
0.46 $
0.91 $
0.22 $
0.11
Weighted average number of unrestricted outstanding common shares to calculate
adjusted net income (loss) per common share - basic and diluted
57,229
52,338
36,379
33,000
22,479
(1) This amount includes premiums accrued but not paid as of the end of the period.
(2) The tax impact is computed by utilizing the Company’s effective tax rate on the adjustments to reconcile net income
(loss) to adjusted net income (loss).
(3) The Company’s restricted shares of common stock are participating securities.
(4) There were no outstanding shares of participating restricted stock for the year ended December 31, 2011.
(5) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314
shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
62
(6) The year ended December 31, 2014 excludes 1,732,888 shares of weighted average restricted stock and 13,527,738
shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
(7) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225
shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
(8) The year ended December 31, 2012 excludes 184,230 shares of weighted average restricted stock and 1,992,857
shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual
Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were
anti-dilutive. The Company had no outstanding stock awards prior to its initial grants in January 2012.
Adjusted Net Income (Loss) is not intended to represent cash flows for the period, nor is it presented as a
substitute for net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any
other measure of financial performance or liquidity presented in accordance with U.S. GAAP.
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 related notes appearing elsewhere in this Annual Report on
Form 10-K.
Business Overview
Sanchez Energy Corporation, a Delaware corporation formed in 2011, is an independent exploration and
production company focused on the exploration, acquisition and development of unconventional oil and natural gas
resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and, to a lesser
extent, the TMS in Mississippi and Louisiana. We have accumulated approximately 200,000 net leasehold acres in the
oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and approximately 62,000 net
leasehold acres in what we believe to be the core of the TMS. We are currently focused on the horizontal development of
significant resource potential from the Eagle Ford Shale, with plans to invest approximately 100% of our 2016 drilling
and completion capital budget in this area. We are continuously evaluating opportunities to grow both our acreage and
our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the
opportunities and the financing alternatives available to us at the time we consider such opportunities. We have included
definitions of some of the oil and natural gas terms used in this Annual Report on Form 10-K in the “Glossary of
Selected Oil and Natural Gas Terms.”
For further discussion of our business, including a description of various acquisitions completed during the
periods presented in the consolidated financial statements, refer to “Item 1. Business—Overview.”
Basis of Presentation
The consolidated financial statements have been prepared in accordance with U.S. GAAP.
Our Properties
We and our predecessor entities have a long history in the Eagle Ford Shale, where we have assembled
approximately 200,000 net leasehold acres with an average working interest of approximately 93%. Using approximately
40 acre well-spacing for our Cotulla and Palmetto areas, approximately 60 acre well-spacing for our Marquis area, and
approximately 75 acre well-spacing for our Catarina area plus up to 650 additional upper Eagle Ford Catarina locations,
63
and assuming 80% of the acreage is drillable for Cotulla, Marquis and Catarina, and 90% of the acreage is drillable for
Palmetto, we believe that there could be over 3,100 gross (2,900 net) locations for potential future drilling. Consistent
with other operators in this area, we perform multi- stage hydraulic fracturing up to 30 stages on each well depending
upon the length of the lateral section. For the year 2016, we plan to invest substantially all of our capital budget in the
Eagle Ford Shale.
Well results in the TMS remain strong although development is currently challenged due to high well costs and
depressed commodity prices. We believe that the TMS play has significant development potential and still has
significant upside as changes in technology, commodity prices, and service prices occur. The average remaining lease
term on the acreage is over 3 years, giving us ample time to allow other industry participants to further de-risk the play.
For further discussion of our properties, including a description of recent well results in our core operating
areas, refer to “Item 1. Business—Core Properties.”
Recent Developments
During the fourth quarter of 2014, oil prices began a substantial and rapid decline, which has continued into
early 2016. In response to that decline, the Company initiated a series of financial and operational activities highlighted
below. Capital expenditures including property acquisition, exploration and development activities totaled approximately
$551 million, which is at the low end of our 2015 capital budget of $550 - $600 million. Our 2016 budget has been set at
$200 - $250 million, which is expected to maintain production around 48,000 to 52,000 boe per day. The 2016 capital
budget remains subject to further adjustments, depending on market conditions, and the Company maintains significant
flexibility in our operations to be able to increase or decrease our capital budget quickly to react to changes in market
conditions.
In January 2016, the Company announced that it had amended the terms under the Second Amended and
Restated Credit Agreement, effective immediately. The amendment allows for the incurrence of second lien debt not to
exceed $400 million plus any principal representing payment of interest in kind. The borrowing base is reduced from
$500 million to $425 million while the aggregate elected commitment amount remains at $300 million. This amendment
is expected to provide the Company with additional financial flexibility and increases available financing and liability
management options. Although the borrowing base was lowered to $425 million, the Company has decided to maintain
the $300 million aggregate elected commitment amount knowing that it has the ability to access the higher borrowing
base upon compliance with certain conditions. The Company’s next scheduled borrowing base redetermination is in the
spring of 2016; the borrowing base is also subject to adjustment in certain circumstances as discussed in Note 5, “Long-
Term Debt – Credit Facility – Second Amended and Restated Credit Agreement.”
Outlook
Due to the uncertainty regarding future commodity prices, the Company plans to manage its operating activities
and financial liquidity carefully. Based on current levels of commodity prices, we expect to be able to fund the current
2016 capital program with cash on hand and operating cash flow. We plan to continuously evaluate our level of
operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations
and make further adjustments to our capital spending program as appropriate. In addition, we expect to continue to
regularly review acquisition opportunities from third parties or other members of the Sanchez Group.
The average oil price, WTI Cushing, used in the SEC pricing methodology for calculating the PV-10 and
Standardized Measures and for performing impairment tests under the full cost method, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31,
2015 was $50.28 per barrel and the average natural gas price, at Henry Hub, and calculated in the same manner, was
$2.58 per mmbtu. As a result of less favorable commodity prices adversely affecting proved reserve values, we recorded
a full cost ceiling test impairment after income taxes of $1,365 million for the year ended December 31, 2015. Based on
the decline in average prices since December 31, 2015 and the fact that the current NYMEX forward prices are below
the year end 2015 SEC prices, absent a material addition to proved reserves and/or a material reduction in future
development costs, there is a reasonable likelihood that the Company could incur additional impairments to our full cost
pool in 2016.
64
Results of Operations
Revenue and Production
The following table summarizes production, average sales prices and operating revenue for our oil, NGLs and
natural gas operations for the periods indicated (in thousands, except average sales price and percentages):
Year Ended December 31,
2014
2015
2013
Increase (Decrease)
2015 vs 2014
$
%
2014 vs 2013
$
%
Net Production:
Oil (mbo)
Natural gas liquids (mbbl)
Natural gas (mmcf)
Total oil equivalent (mboe)
7,164.7
5,754.1
37,594.1
19,184.4
6,079.6
2,590.1
14,827.5
11,141.0
2,908.6
455.0
1,085.1
18 %
3,164.0 122 %
3,048.5 22,766.6 154 %
72 %
3,871.6
8,043.4
3,171.0
2,135.1
11,779.0
7,269.4
109 %
*
*
188 %
Average Sales Price Excluding Derivatives(1):
Oil ($ per bo)
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)
Oil equivalent ($ per boe)
$
$
42.98 $
11.99
2.63
24.80 $
88.64 $
25.86
4.06
59.79 $
99.82 $
28.60
3.64
81.21 $
(45.66) (52) % $
(13.87) (54) %
(1.43) (35) %
(34.99) (59) % $
(11.18)
(2.74)
0.42
(21.43)
(11) %
(10) %
12 %
(26) %
Average Sales Price Including Derivatives(2):
Oil ($ per bo)
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)
Oil equivalent ($ per boe)
$
$
60.28 $
11.99
3.12
32.23 $
89.26 $
25.86
4.13
60.22 $
96.86 $
28.60
3.63
78.98 $
(28.98) (32) % $
(13.87) (54) %
(1.01) (24) %
(27.99) (46) % $
(7.60)
(2.74)
0.50
(18.76)
(8) %
(10) %
14 %
(24) %
REVENUES(1):
Oil sales
Natural gas liquids sales
Natural gas sales
Total revenues
* Not meaningful.
$ 307,971 $ 538,887 $ 290,322 $ (230,916) (43) % $ 248,565
53,976
49,103
$ 475,779 $ 666,064 $ 314,420 $ (190,285) (29) % $ 351,644
66,989
60,188
13,013
11,085
69,011
98,797
2,022
38,609
3 %
64 %
86 %
*
*
112 %
(1) Excludes the realized impact of derivative instruments.
(2) Includes the realized impact of derivative instruments.
Net Production. Production increased from 11,141.0 mboe in 2014 to 19,184.4 mboe in 2015 due to our
drilling program and a full year of production from our Catarina wells acquired in 2014. The number of gross wells
producing at year end and the production for the periods were as follows:
2015
Year Ended December 31,
2014
2013
# Wells mboe
# Wells mboe
# Wells mboe
Catarina
Cotulla
Marquis
Palmetto
Other
Total
287
145
103
72
14
621
13,904.8
2,517.4
1,815.6
873.6
73.0
19,184.4
193
129
90
64
9
485
3,966.9
3,047.6
2,324.0
1,770.7
31.8
11,141.0
—
100
34
53
1
188
65
—
1,536.4
852.2
1,478.1
4.9
3,871.6
In 2015, 37% of our production was oil, 30% was NGLs and 33% was natural gas compared to 2014 production
that was 55% oil, 23% NGLs and 22% natural gas. In 2013, 75% of our production was oil, 12% NGLs and 13% natural
gas. The change in production mix during the year ended December 31, 2014 was due to the Catarina Acquisition and
the higher proportion of NGL and natural gas production as compared to oil production from this area. Throughout the
year ended December 2015, production from Catarina continued to increase in proportion to the total production, and as
such, a higher proportion of NGL and natural gas was produced as compared to oil.
Revenues. Oil, NGL and natural gas sales revenues totaled approximately $475.8 million, $666.1 million, and
$314.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Oil revenue for the year ended
December 31, 2015 decreased $230.9 million, while revenues from NGL and natural gas sales revenue for the year
ended December 31, 2015 increased $2.0 million and $38.6 million, respectively, as compared to the year ended
December 31, 2014.
The following tables provide an analysis of the impacts of changes in average realized prices and production
volumes between the periods on our revenues from the year ended December 31, 2014 to the year ended December 31,
2015 (in thousands, except average sales price):
Oil (mbo)
Natural gas liquids (mbbl)
Natural gas (mmcf)
Total oil equivalent (mboe)
7,164.7
5,754.1
37,594.1
19,184.4
6,079.6
2,590.1
14,827.5
11,141.0
2015
2014
Production
Volume
Production
Volume
Production
Volume
Difference
2014
Revenue
Average Sales Increase/(Decrease)
due to Production
96,176
81,834
92,412
270,422
Price
88.64 $
25.86 $
4.06 $
59.79 $
1,085.1 $
3,164.0 $
22,766.6 $
8,043.4 $
Oil (mbo)
Natural gas liquids (mbbl)
Natural gas (mmcf)
Total oil equivalent (mboe)
2015
Price
2014
Average Sales Average Sales Average Sales
Price
88.64 $
25.86 $
4.06 $
59.79 $
42.98 $
11.99 $
2.63 $
24.80 $
(45.66)
(13.87)
(1.43)
(34.99)
$
$
$
$
2015
Revenue
Production Increase/(Decrease)
7,164.7 $
5,754.1 $
37,594.1 $
19,184.4 $
due to Price
(327,092)
(79,812)
(53,803)
(460,707)
Price Difference Volume
Additionally, a 10% increase or decrease in our average realized sales prices, excluding the impact of
derivatives, would have increased or decreased our revenues for the year ended December 31, 2015 by $47.6 million.
For the year ended December 31, 2014 compared to 2013, oil sales revenue increased $248.6 million with
$316.5 million attributable to the increase in production partially offset by $68.0 million due to the lower average sales
price. NGL sales revenue for the year ended December 31, 2014 increased $54.0 million as compared to 2013, with
$61.1 million attributable to the increase in production partially offset by $7.1 million attributable to the lower average
sales prices between the periods. Natural gas sales revenue for the year ended December 31, 2014 increased
approximately $49.1 million with $42.9 million attributable to the increase in production and $6.3 million due to the
higher average sales price compared to 2013.
66
Operating Costs and Expenses
The table below presents a detail of operating costs and expenses for the periods indicated (in thousands except
percentages):
Year Ended December 31,
2015
2014
2013
2015 vs 2014
$
%
2014 vs 2013
%
$
Increase (Decrease)
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses
Production and ad valorem taxes
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
General and administrative (1)
Total operating costs and expenses
$
156,528 $ 93,581 $ 35,669 $
37,787
26,870
338,097
344,572
213,821
1,365,000
63,692
74,160
746,978
1,967,130
17,334
134,845
—
47,951
235,799
62,947
(10,917)
6,475
1,151,179
10,468
1,220,152
67 % $ 57,912
20,453
(29) %
203,252
2 %
213,821
*
15,741
16 %
511,179
163 %
Interest income and other income (expense)
Interest expense
(2,163)
(126,399)
289
(89,800)
135
(30,934)
(2,452)
36,599
*
(41) %
154
58,866
Net gains on commodity derivatives
Income tax benefit (expense)
172,886
(7,600)
137,205
11,429
(16,938)
(3,986)
35,681
(19,029)
26 %
*
154,143
15,415
162 %
118 %
151 %
*
33 %
217 %
114 %
*
*
*
* Not meaningful.
(1) Includes stock-based compensation expense of $14.8 million, $12.8 million, and $17.8 million for the year ended
December 31, 2015, 2014 and 2013, respectively, and includes acquisition and divestiture costs of $3.8 million, $1.8
million, and $4.1 million for the years ended December 31, 2015, 2014, and 2013, respectively.
Oil and Natural Gas Production Expenses. Oil and natural gas production expenses are the costs incurred to
produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also
include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional well
workover expenses related to our oil and natural gas properties. Our oil and natural gas production expenses increased
67% to $156.5 million for the year ended December 31, 2015, as compared to $93.6 million for the same period in 2014
and $35.7 million for the same period in 2013. The increase in oil and natural gas production expenses from 2013 to
2015 is directly attributable to our increased production activities and well count in the Eagle Ford Shale, as a result of
the Catarina, Wycross and Cotulla Acquisitions completed during 2014 and 2013, as well as drilling activities on our
existing acreage. Our average production expenses decreased from $8.40 per boe during the year ended December 31,
2014 to $8.16 per boe for the year ended December 31, 2015. This decrease was due primarily to increased efficiency in
our overall operations between the periods. While we expect our oil and natural gas production expenses to increase as
we add producing wells, we expect to continue our efficient operation of our properties, and do not expect significant
increases in our average production expenses per boe.
Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based upon a
percentage of gross revenues or at fixed rates established by state or local taxing authorities. Ad valorem taxes are paid
based upon the appraised fair market value of producing properties using an estimated discounted cash flow approach by
a fixed rate established by state or local taxing authorities. Our production and ad valorem taxes totaled $26.9 million,
$37.8 million and $17.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. The tax decrease
from 2014 to 2015 is attributable to the decrease in revenues of 29% between the periods and the decrease in appraised
property values due to the decline in commodity prices between the periods. This tax increase from 2013 to 2014 was
due to the significant increase in revenues of over 112% between these periods. Our average production and ad valorem
taxes decreased from $3.39 per boe during the year ended December 31, 2014 to $1.40 per boe for the year ended
December 31, 2015. This decrease in rate is attributable to the decrease in expense by 29% from 2014 to 2015 coupled
with the increase in production volumes by 72% from 2014 to 2015. In addition, a lower production tax rate is applied to
Catarina wells as a result of the characterization of the wells in the Catarina area as high cost gas wells. Catarina
accounted for approximately 72% of the total Company production in 2015. While this rate may vary depending on the
67
actual capital costs incurred on a well by well basis, we expect the production tax rate to continue to be lower than the
rates established in our other operating areas.
Depreciation, Depletion, Amortization, and Accretion. Depletion, depreciation, amortization, and accretion
(“DD&A”) reflects the systematic expensing of the capitalized costs incurred in the acquisition, exploration and
development of oil and natural gas properties. We use the full-cost method of accounting and accordingly, we capitalize
all costs associated with the acquisition, exploration and development of oil and natural gas properties, including
unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to
acquisition, exploration and development activities and do not include any costs related to production, selling or general
corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the units of
production method based upon production and estimates of proved oil and natural gas reserve quantities. Unproved and
unevaluated property costs are excluded from the amortizable base used to determine DD&A expense.
Our DD&A expense for the year ended December 31, 2015 increased $6.5 million to $344.6 million ($17.96
per boe) from $338.1 million ($30.35 per boe) in 2014 and $134.8 million in 2013 ($34.83 per boe). The majority of the
increase in DD&A is related to an increase in depletion resulting primarily from a substantial increase in production
between periods. This was offset by a decrease in the depletion rate, resulting primarily from a decrease in the full-cost
pool proved property amortization base as result of approximately $1,579 million of full-cost ceiling impairments
recorded during the fourth quarter 2014, the first quarter 2015, the second quarter 2015, and the third quarter 2015
combined. We did not record a full-cost ceiling impairment during the fourth quarter 2015. Higher production in 2015 as
compared to 2014 resulted in a $244.1 million increase in depletion expense and the change in depletion rate resulted in
an offsetting $237.6 million decrease in depletion expense. The majority of the increase in DD&A from 2013 to 2014 is
related to an increase in production between the periods offset by a decrease in the depletion rate. The depletion rate
decreased due to an increase in the estimated proved reserves during the period, largely as a result of the Catarina
Acquisition. Higher production in 2014 as compared to 2013 resulted in a $252.4 million increase in depletion expense
and the change in depletion rate resulted in a $51.1 million decrease in depletion expense.
Impairment of Oil and Natural Gas Properties. We utilize the full cost method of accounting to account for our
oil and natural gas exploration and development activities. Under this method of accounting, we are required on a
quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated
properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of
the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties
over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment
after income taxes of $441.5 million, $468.9 million, and $454.6 million for the three months ended March 31, 2015,
June 30, 2015, and September 30, 2015, respectively. We did not record a full-cost ceiling impairment during the fourth
quarter 2015. We recorded a full cost ceiling test impairment before income taxes of $213.8 million for the year ended
December 31, 2014. The combined impact of less favorable commodity prices adversely affecting proved reserve values
and the historical costs to drill and complete wells carried as proved undeveloped, as compared to current drilling and
completion costs, contributed to the ceiling impairments. Changes in production rates, levels of reserves, future
development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation
and impairment analyses in future periods. Given the current trend in commodity prices, the Company expects a
continued decline in 12-month average commodity prices, and, therefore, additional impairments could be recorded
during 2016.
If the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-month
period ended December 31, 2015 had been $2.45 per mmbtu for natural gas, $46.03 per Bbl of oil, and $18.12 per Bbl of
NGL, while all other factors remained constant, our ceiling test limitation related to the net book value of our proved oil
and natural gas properties would have been reduced by approximately $134.4 million and our net PUD and total proved
reserves would have been reduced by approximately 38.2 mmboe and 43.1 mmboe, respectively. The aforementioned
prices were calculated based on a 12-month simple average, which includes the oil and natural gas prices on the first day
of the month for the 11 months ended February 2016 and the February 2016 prices were held constant for the remaining
one month. This reduction in our ceiling test limitation would have resulted in an impairment of our oil and natural gas
properties pursuant to the ceiling test by approximately $21.0 million on a pro forma basis. The pro forma reduction in
our ceiling test limitation is partially the result of a pro forma decrease in our proved reserves, which was primarily due
68
to certain locations that would not be economical when using the pro forma prices. This calculation of the impact of
lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant
with the exception of oil, natural gas, and NGL prices. Therefore, this calculation strictly isolates the impact of
commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the
estimation of our proved reserves and other factors noted above could have a significant impact on future reserves and
the present value of future cash flows. There are numerous uncertainties inherent in the estimation of proved reserves
and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be
construed as indicative of our development plans or future results.
General and Administrative Expenses. Our general and administrative (“G&A”) expenses, including
stock-based compensation expense and costs associated with acquisitions and divestures, totaled $74.2 million for the
year ended December 31, 2015 compared to $63.7 million and $48.0 million for the same periods in 2014 and 2013,
respectively. Excluding stock-based compensation and acquisition and divestiture costs included in G&A, our G&A
expenses totaled $55.5 million, $49.0 million, and $26.1 million for the years ended December 31, 2015, 2014 and 2013,
respectively. This increase was due primarily to additional costs for added personnel at SOG performing services for the
Company and for consulting services and increased fees for legal services during 2015. Our G&A expenses per boe,
excluding stock-based compensation expense and acquisition and divestiture costs included in G&A, decreased from
$4.40 per boe for the year ended December 31, 2014 to $2.89 per boe for the year ended December 31, 2015.
We recorded non-cash stock-based compensation expense of $14.8 million for the year ended December 31,
2015 as compared to expense of $12.8 million for the year ended December 31, 2014. The increase was due primarily to
the increase in awards made during the year and the associated amortization recognized, slightly offset by the decrease in
the stock price. We recorded non-cash stock-based compensation expense of $17.8 million for the year ended
December 31, 2013. The decrease from 2013 to 2014 was due primarily to the decrease in stock price offset by an
increase in awards made during the year and the associated amortization recognized. The Company records stock-based
compensation expense for awards granted to non-employees at fair value and the unvested awards are revalued each
period, impacting the amortization over the remaining life of the awards.
We recorded costs associated with the Palmetto Disposition and the Western Catarina Midstream Divestiture
that are included in G&A of $3.8 million for the year ended December 31, 2015. We recorded costs associated with the
Catarina Acquisition of $1.8 million for the year ended December 31, 2014, and we recorded costs associated with the
Wycross, the Five Mile Creek and the Cotulla Acquisitions of $4.1 million for the year ended December 31, 2013.
Interest Expense. For the year ended December 31, 2015, interest expense totaled $126.4 million and included
$7.5 million in amortization of debt issuance costs. This is compared to the year ended December 31, 2014, for which
interest expense totaled $89.8 million and included $9.0 million in amortization of debt issuance costs and write-offs of
previously incurred debt issuance costs in connection with the unused senior unsecured bridge facility obtained as part of
the Catarina Acquisition that expired. The interest expense incurred during the year ended December 31, 2015 is
primarily related to the 7.75% Notes (as defined in Note 5, “Long-Term Debt”) and 6.125% Notes (as defined in Note 5,
“Long-Term Debt”).
Commodity Derivative Transactions. We apply mark-to-market accounting to our derivative contracts;
therefore, the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in other income
and expenses. During the year ended December 31, 2015, we recognized a net gain of $172.9 million on our commodity
derivative contracts, which included net gains of $142.5 million associated with the settlements of commodity derivative
contracts. These gains were primarily the result of the significant decreases in commodity prices during the period.
During the year ended December 31, 2014, we recognized a net gain of $137.2 million on our commodity derivative
contracts, which included net gains of $5.6 million associated with the settlements of commodity derivative contracts
offset by $0.7 million related to the premiums paid on derivative contracts. These gains were primarily the result of the
significant decreases in commodity prices during the period. During the year ended December 31, 2013, we recognized a
net loss of $16.9 million on our commodity derivative contracts, which included net losses of $5.8 million associated
with the settlements of commodity derivative contracts and $2.8 million related to the premiums paid on derivative
contracts.
69
Income tax expense. For the year ended December 31, 2015, the Company recorded income tax expense of
$7.6 million. Our effective tax rate for the year ended December 31, 2015 was (0.53)% as compared to a statutory rate of
35%. The difference between the statutory rate and the Company’s effective tax rate is related to the valuation allowance
of approximately $515 million recorded during the period. For the year ended December 31, 2014, the Company
recorded income tax benefit of $11.4 million. Our effective tax rate for the year ended December 31, 2014 was 34.4% as
compared to a statutory rate of 35%. The difference between the statutory rate and the Company’s effective tax rate is
related to non-deductible G&A expenses recorded during the period. We expect our effective tax rate going forward to
be approximately 0% as we have recorded a full valuation allowance against our net deferred tax assets.
Liquidity and Capital Resources
As of December 31, 2015, we had approximately $435 million in cash and cash equivalents and a $500 million
unused, available borrowing base (with a $300 million aggregate elected commitment amount) under our revolving
credit facility with a group of sixteen participating banks. This available liquidity of approximately $735 million
excludes the additional $200 million of approved revolving credit facility borrowing base which we elected not to accept
at this time, but which may be utilized subject to the satisfaction of certain conditions, including the consent of lenders
whose commitments are increased.
We expect to use a portion of our cash on hand and our internally generated cash flows from operations to fund
our 2016 capital expenditures, while still being able to keep production volumes in line with 2015 results. The Company
recently announced a new 2016 capital spending plan of approximately $200 to $250 million, a decrease from previous
preliminary estimates by $50 million. The new spending plan was approved in light of the depression in commodity
prices currently and expected for all of 2016. We may from time to time seek to retire or purchase our outstanding debt
as well as our outstanding equity securities, both common stock and preferred stock, through cash purchases and/or
exchanges for equity securities and/or debt securities, as applicable, in open market purchases, privately negotiated
transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our
liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
For a description of current and previous credit agreements along with the indentures covering our Senior Notes
refer to Note 5, “Long-Term Debt.”
Cash Flows
Our cash flows for the years ended December 31, 2015, 2014 and 2013 are as follows (in thousands):
Cash Flow Data:
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Year Ended December 31,
2014
2015
2013
$
$
$
415,335 $
272,024 $
189,261
(294,331) $ (1,361,264) $ (1,093,363)
(16,359) $ 1,266,112 $ 1,007,286
Net Cash Provided by Operating Activities. Net cash provided by operating activities was $272.0 million for
the year ended December 31, 2015 compared to $415.3 million and $189.3 million for the same periods in 2014 and
2013, respectively. This decrease was related to the unfavorable impact of lower average commodity prices between the
periods, partially offset by higher sales volumes.
One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuations
in commodity prices, the impact of which the Company partially mitigates by entering into commodity derivatives. Sales
volume changes also impact cash flow. The Company’s cash flows from operating activities are also dependent on the
costs related to continued operations and debt service.
70
Net Cash Used in Investing Activities. Net cash flows used in investing activities totaled $294.3 million for the
year ended December 31, 2015 compared to $1.4 billion and $1.1 billion for the same periods in 2014 and 2013,
respectively. Capital expenditures for leasehold and drilling activities for the year ended December 31, 2015 totaled
$656.1 million, primarily associated with bringing online 136 gross wells. We received total cash of approximately
$427.6 million for the Palmetto Disposition and the Western Catarina Midstream Divestiture, while spending
approximately $50.0 million towards equity method investments (further discussed in Note 16, “Investments”) and $8.0
million for the Buyout Agreement (defined in Note 9, “Related Party Transactions” below). In addition, we invested
$8.1 million in other assets. For the year ended December 31, 2014, we incurred capital expenditures for leasehold and
drilling activities of $791.3 million, primarily associated with bringing online 121 gross wells. We paid cash of
$557.1 million for the oil and natural gas properties acquired in the Catarina Acquisition. We received cash of
$0.7 million and $0.5 million as final settlement for the oil and natural gas properties acquired in the Cotulla and
Wycross Acquisitions, respectively. In addition, we invested $14.1 million in other property and equipment. For the year
ended December 31, 2013, we incurred capital expenditures of $479.9 million, primarily associated with bringing online
83 gross wells. We paid cash of approximately $623.0 million for the oil and natural gas properties acquired in the
Cotulla Acquisition, the TMS Transaction, the Wycross Acquisition as well as other less material acquisitions of oil and
natural gas properties. In addition, we invested $2.1 million in computers and other equipment. Partially offsetting these
costs were proceeds of $11.6 million from the sale of marketable securities.
Net Cash Provided by (Used in) Financing Activities. Net cash flows used in financing activities totaled $16.4
million for the year ended December 31, 2015 compared to $1.3 billion and $1.0 billion in cash provided by financing
activities for the same period in 2014 and 2013, respectively.
During the year ended December 31, 2015, we made payments of $16.0 million for dividends on our Series A
Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock.
During the year ended December 31, 2014, we received net proceeds from the issuance of common stock of
$167.5 million, after deducting offering costs payable by us of $8.7 million. We also made payments of $16.3 million for
dividends on our Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock. We
received net proceeds of approximately $1.12 billion from the issuance of our 6.125% Notes, consisting of a face value
of $1.15 billion, including the Additional 6.125% Notes which were issued at a premium to face value of $2.3 million,
less debt issuance costs of $27.4 million. Other debt issuance costs for the year ended December 31, 2014 totaled
$10.0 million. On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit
Agreement. The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million
outstanding under the Amended and Restated Credit Agreement, in addition to funding a portion of the purchase price of
the Catarina Acquisition.
During the year ended December 31, 2013, we received net proceeds from the private placement of our Series B
Convertible Perpetual Preferred Stock of approximately $216.6 million, after deducting placement agent’s fees and
offering costs payable by us of approximately $8.4 million. We also received net proceeds of approximately
$577.0 million from the private placement of our 7.75% Notes, consisting of face value of $600 million, including the
Additional 7.75% Notes which were issued at a discount to face value of $7 million, less debt issuance costs of
approximately $16 million, included in the $24.1 million discussed below. During the three months ended September 30,
2013, the Company completed a public offering of common stock, and received net proceeds from this offering of
approximately $241.5 million, after deducting underwriter’s fees and other expenses of approximately $12.4 million.
During the three months ended March 31, 2013, we borrowed $50 million under the Second Lien Credit Agreement (the
“Second Lien Credit Agreement”). On May 30, 2013, we borrowed $90 million under the Original Credit Agreement
(the “Original Credit Agreement”). On May 31, 2013, we borrowed $96 million under our Amended and Restated Credit
Agreement, and used the proceeds to repay the $90 million borrowed under our Original Credit Agreement. The
outstanding borrowings under our Amended and Restated Credit Agreement and Second Lien Credit Agreement were
repaid during the three months ended June 30, 2013 with proceeds from the offering of the Original 7.75% Notes. Other
financing costs for the year ended December 31, 2013 included $24.1 million for debt issuance costs, $18.5 million paid
for preferred stock dividends and $1.1 million paid for the purchase of common stock to settle taxes on the vesting of
employee stock grants.
71
Commitments and Contractual Obligations
Refer to Note 14, “Commitments and Contingencies” for a description of lawsuits pending against the
Company.
During the year ended December 31, 2015, the Company entered into the Gathering Agreement with SPP as
part of the Western Catarina Midstream Divestiture (defined below in Note 3, “Acquisitions and Divestitures”) that
provides a firm commitment of oil and natural gas volumes at a fixed gathering fee. The Gathering Agreement represents
an operating lease of the Catarina midstream assets. The firm commitment term under the Gathering Agreement
commenced on October 14, 2015 and continues until October 13, 2020. As of December 31, 2015, our contractual
obligations included our Senior Notes, interest expense on our Senior Notes, asset retirement obligations, rent expense
for our corporate offices, lease of the Catarina midstream assets and other long term lease payments. The following table
summarizes our contractual obligations as of December 31, 2015 (in thousands):
Less than 1
year
1 - 3 years 3 - 5 years
5 years
Total
More than
Senior Notes
Interest expense (1)
Asset retirement obligations (2)
Office rent (3)
Midstream assets lease (4)
Other leases (5)
Total
$
— $
— $
233,875
— $ 1,750,000 $ 1,750,000
784,031
25,907
50,804
10,856
200,682
74,782
13,880
3,583
$ 165,904 $ 331,826 $ 323,096 $ 2,004,478 $ 2,825,304
116,938
—
5,132
42,043
1,791
233,875
—
10,511
83,857
3,583
25,907
24,305
—
4,923
199,343
—
(1) Represents estimated interest payments that will be due under the $600 million 7.75% Notes and $1,150 million
6.125% Notes that will mature on June 15, 2021 and January 15, 2023, respectively.
(2) Amounts represent the present value of our estimate of future asset retirement obligations. Because these costs
typically extend many years into the future, estimating these future costs requires management to make estimates
and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation,
changing technology and the political and regulatory environment. See Note 12, “Asset Retirement Obligations.”
(3) Represents payments due for leasing corporate office space in Houston, Texas. The lease began on November 1,
2014 and continues until March 31, 2025.
(4) Represents payments due with respect to firm commitment oil and natural gas volumes under the Gathering
Agreement contract signed with SPP as part of the Western Catarina Midstream Divestiture. As part of this sale, the
Gathering Agreement represents an operating lease of the Catarina midstream assets. The firm commitment term
under the Gathering Agreement commenced on October 14, 2015 and continues until October 13, 2020.
(5) Represents payments due for a ground lease agreement for land owned by the Calhoun Port Authority which
commenced on August 25, 2014 and continues until August 25, 2024. Also represents payments due for an acreage
lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas which commenced on
March 1, 2014 and continues until February 28, 2024.
In connection with the Catarina Acquisition, the 77,000 acres of undeveloped acreage that were included in the
acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each
annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120-day period in order to
maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given
annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for
well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty
payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the
minimum number of wells required to maintain access to such undeveloped acreage.
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The Company’s ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the
Company to the lessor in addition to a $1 million termination payment. In connection with the lease agreement for
acreage in Kenedy County, Texas, there is a contractual requirement for the Company to spend a minimum of $4 million
to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for
such improvements to be made within the lease term. The Company has the right to terminate its lease obligation at any
time without penalty with six months advanced written notice and payment of any accrued leasehold expenses.
Off-Balance Sheet Arrangements
As of December 31, 2015, we did not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon consolidated
financial statements that have been prepared in accordance with U.S. GAAP. The preparation of these consolidated
financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses. Our significant accounting policies are described in Note 2, “Basis of Presentation and Summary
of Significant Accounting Policies.” When we prepare our financial statements, we review our estimates, including those
related to oil, NGL and natural gas revenues, oil and natural gas properties, oil, NGL and natural gas reserves, fair value
of derivative instruments, abandonment liabilities, income taxes, commitments and contingencies, depreciation,
depletion and amortization, and full cost ceiling calculation. Our estimates are based on historical experience and various
assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates
under different assumptions or conditions. We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties
The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All
direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas
properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in
the amortization base and amortized to depletion expense using the units-of-production method. Depletion is calculated
based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas
properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the
relationship between costs and the estimated quantities of proved reserves.
Full Cost Ceiling Test—Capitalized costs (net of accumulated depreciation, depletion and amortization and
deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling
limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from
estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage
value) and estimated related future income taxes. In accordance with SEC rules, the oil and natural gas prices used to
calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless
prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held
constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess
is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be
written off are not reinstated for any subsequent increase in the cost center ceiling. During the year ended December 31,
2015, the Company recorded a full cost ceiling test impairment after income taxes of $1,365 million. During the year
ended December 31, 2014, the Company recorded a full cost ceiling test impairment before income taxes of $213.8
million. No impairment expense was recorded for the years ended December 31, 2013.
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Depreciation, depletion, amortization and accretion—DD&A is provided using the units-of-production method
based upon estimates of proved oil, NGL and natural gas reserves with oil, NGL and natural gas production being
converted to a common unit of measure based upon their relative energy content. All capitalized costs of oil and natural
gas properties, including the estimated future costs to develop proved reserves, are amortized using the
units-of-production method based on total proved reserves. Investments in unproved properties and major development
projects are not amortized until proved reserves associated with the projects can be determined or until impairment
occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to
the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major
development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool
and amortization begins. The amortizable base includes estimated future development costs and where significant,
dismantlement, restoration and abandonment costs, net of estimated salvage value.
In arriving at depletion rates under the units-of-production method, the quantities of recoverable oil and natural
gas reserves are established based on estimates made by internal and third party geologists and engineers, which require
significant judgment as does the projection of future production volumes and levels of future costs, including future
development costs. In addition, considerable judgment is necessary in determining when unproved properties become
impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may
have significant impact on the calculation of depletion and impairment expense. At December 31, 2015, a 10% positive
revision to proved reserves would decrease the depletion rate by approximately $1.60 per boe and a 10% negative
revision to proved reserves would increase the depletion rate by approximately $1.94 per boe. Further, a 10% increase or
decrease in estimated future development costs would increase or decrease the depletion rate by approximately $0.71 per
boe at December 31, 2015.
Unproved Properties—Costs associated with unproved properties and properties under development are
excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated
with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base.
Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests
are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred
into the full cost pool subject to amortization when management determines that a project area has been evaluated
through drilling operations or thorough geologic evaluation, or through determination that the unproved leases will no
longer be drilled upon prior to the lease expiration.
Oil and Natural Gas Reserves
The Company’s most significant estimates relate to its proved oil, NGL and natural gas reserves. The estimates
of oil, NGL and natural gas reserves as of December 31, 2015, 2014 and 2013 are based on reports prepared by a third
party engineering firm, Ryder Scott.
Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological
analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current
operating and economic parameters. Ryder Scott has historically prepared a reserve and economic evaluation of the
Company’s properties, utilizing information provided to it by management and other information available, including
information from the operators of the property.
The standards of the FASB and rules of the SEC permit the use of new technologies to determine proved
reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve
volume estimates. These rules allow, but do not require, companies to disclose their probable and possible reserves to
investors in documents filed with the SEC.
In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average
price based upon the prior 12-month first-day-of-the-month price rather than a period-end price.
74
Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations.
As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The
reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC
guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve
reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of
available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the
judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As
such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Additionally, with other factors held constant, if the commodity prices used in our reserve report as of December 31,
2015 had decreased by 10%, then the standardized measure of our estimated proved reserves as of that date would have
decreased by approximately $200.7 million, from approximately $593.5 million to approximately $392.8 million.
Asset Retirement Obligations
Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to
plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in
accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of
plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. The inputs are
calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying
amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the
capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is
treated as an adjustment to the full cost pool.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities
arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax
basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary difference and carryforwards are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the
amount more likely than not to be recovered.
Additionally, the Company is required to determine whether it is more likely than not (a likelihood of more than
50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation
processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is
satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the
financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood
of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax
expense.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for
income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate
tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these
estimates, which could impact the Company’s financial position, results of operations and cash flows. The Company
does not have any material uncertain tax positions during the years ended December 31, 2015, 2014 or 2013.
Stock-Based Compensation
The Company records stock-based compensation expense for awards granted to its directors (for their services
as directors) in accordance with the provisions of ASC 718, “Compensation—Stock Compensation.” Stock-based
compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using
the straight-line method.
75
Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also
serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and
the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions
of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Company
records compensation expense equal to the fair value of the stock-based award at the measurement date, which is
determined to be the earlier of the performance commitment date or the service completion date. Compensation expense
for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the
stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is
more determinable than the value of the services rendered.
For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair
value re-measured at each reporting period and recognized over the vesting period using the straight-line method.
Compensation expense for these awards will be revalued at each period end until vested.
Revenue Recognition
Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable
price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title
is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The
sales method of accounting is used for oil, NGL and natural gas sales such that revenues are recognized based on our
share of actual proceeds from the oil, NGLs and natural gas sold to purchasers. Oil and natural gas imbalances are
generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take
more or less than their respective entitled percentage.
Derivative Instruments
At times we may utilize derivative instruments to manage our exposure to fluctuations in the underlying
commodity prices for the products sold by us. The carrying amount of derivative assets and liabilities is reported on the
balance sheet at the estimated fair value of the derivative instruments. Our management sets and implements all of our
hedging policies, including volumes, types of instruments and counterparties, on a monthly basis. These derivative
transactions are not designated as cash flow hedges. Accordingly, these derivative contracts are marked-to-market and
any changes in the estimated value of derivative contracts held at the balance sheet date are recognized in the statement
of operations as net gains (losses) on commodity derivatives.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and, potentially,
interest rates as described below.
The primary objective of the following information is to provide quantitative and qualitative information about
our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in
oil, NGLs and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected
future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were
entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production.
Realized pricing is primarily driven by the prevailing market prices applicable to our oil, NGL and natural gas
production. Pricing for oil, NGL and natural gas has been volatile and unpredictable for several years, and this volatility
is expected to continue in the future. The prices we receive for our oil, NGL and natural gas production depend on many
factors outside of our control, such as the strength of the global economy.
76
To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the
economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of
its projected oil and natural gas production through various transactions that fix or, through options, modify the future
prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its
production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into
collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the
floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put
spreads, as a way to manage its exposure to fluctuating prices. These hedging activities are intended to support oil and
natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the
Company’s intention to enter into derivative contracts for speculative trading purposes. Please refer to Note 10,
“Derivative Instruments” for a description of all of our derivatives covering anticipated future production as of
December 31, 2015.
At December 31, 2015, the fair value of our commodity derivative contracts was a net asset of $172.5 million.
A 10% increase in the oil and natural gas index prices above the December 31, 2015 prices would result in a decrease in
the fair value of our commodity derivative contracts of $40.8 million; conversely, a 10% decrease in the oil and natural
gas index prices would result in an increase of $41.7 million.
In February 2015, the Company modified certain of its crude oil enhanced swap and three-way collar
transactions to create crude oil swaps on a costless transactional basis. The modification to a fixed price eliminates
downside risk, preserves value and provides the Company with greater certainty in crude oil pricing for the remainder of
2015. We have commodity derivative contracts in place covering approximately 70% of the mid-point of our total
estimated production for 2016.
Interest Rate Risk
As of December 31, 2015, no amounts were outstanding under our Second Amended and Restated Credit
Agreement. Our 7.75% Notes bear a fixed interest rate of 7.75% with an expected maturity date of June 15, 2021, and we
had $600 million outstanding as of December 31, 2015. Our 6.125% Notes bear a fixed interest rate of 6.125% with an
expected maturity date of January 15, 2023, and we had $1.15 billion outstanding as of December 31, 2015. We
currently do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating
interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to
mitigate the risk of fluctuating interest rates.
Item 8. Financial Statements and Supplementary Data
The information required by this Item is included in this report as set forth in the “Index to Consolidated
Financial Statements” on page F-1 and is incorporated by reference herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On June 19, 2015, the Company (i) dismissed BDO USA, LLP (“BDO”) as the Company’s independent
registered public accounting firm and (ii) appointed KPMG LLP (“KPMG”), effective immediately, to serve as the
Company’s new independent registered public accounting firm to audit the Company’s financial statements as of and for
the fiscal year ending December 31, 2015. The Audit Committee of the Company pursuant to its charter exercised its
sole authority to approve BDO’s dismissal and KPMG’s appointment as the Company’s independent registered public
accounting firm.
The reports of BDO on the financial statements of the Company as of and for the fiscal years ended
December 31, 2014 and 2013 did not contain any adverse opinion or disclaimer of opinion, and were not qualified or
modified as to uncertainty, audit scope or accounting principles. During the Company’s fiscal years ended December 31,
2014 and 2013, and the interim period through June 19, 2015, (i) the Company had no disagreements with BDO on any
matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which
disagreements, if not resolved to BDO’s satisfaction, would have caused BDO to make reference to the subject matter of
77
such disagreements in its reports on the financial statements of the Company for such years and (ii) there were no
reportable events of the type described in Item 304(a)(1)(v) of Regulation S-K under the Securities Exchange Act of
1934, as amended, except the following material weakness:
1.
In connection with the performance of its audit of the Company’s financial statements for the year
ended December 31, 2014, BDO reported that our internal control over financial reporting was not
effective as of December 31, 2014 as a result of the identification of one material weakness related to
an over-estimation of future development costs in the year-end reserve report. This material weakness
was disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31,
2014.
The Company provided BDO with a copy of the foregoing disclosure and requested that BDO furnish the
Company with a letter addressed to the SEC stating whether or not BDO agreed with the statements above concerning
BDO. In a letter attached to the Current Report on Form 8-K filed on June 23, 2015, BDO stated that it agreed with the
aforementioned disclosure.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management, including our
Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure
controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15 promulgated pursuant
to the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded
that, as of the end of the fourth quarter of 2015, our disclosure controls and procedures were effective to provide a
reasonable assurance that material information required to be disclosed by using reports that we file or submit under the
Exchange Act is appropriately recorded, processed, summarized and reported within the time periods specified in the
SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the
Exchange act is accumulated and communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management concluded that the consolidated financial statements included in this Annual Report on Form 10-K
fairly present, in all material respects, the financial position of the Company at December 31, 2015 and 2014 and the
consolidated results of operations and cash flows for each of the three years in the period ended December 31, 2015 in
conformity with U.S. GAAP.
Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of the
Registered Public Accounting Firm
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system
of internal control over financial reporting, no matter how well designed, has inherent limitations, including the
possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only
reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal
control over financial reporting in future periods can change as conditions change. A material weakness is a deficiency,
or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility
that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely
basis.
78
Our management assessed the effectiveness of our internal control over financial reporting as of December 31,
2015. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on this assessment and such
criteria, our management concluded that our internal control over financial reporting was effective as of December 31,
2015.
KPMG, an independent registered public accounting firm, has issued its report on the effectiveness of the
Company’s internal control over financial reporting at December 31, 2015. The report from KPMG is included in this
Item under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial
Reporting.”
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the three months ended
December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
Item 9B. Other Information
None.
79
Item 10. Directors, Executive Officers and Corporate Governance
PART III
Information regarding our directors, executive officers and certain corporate governance items will be included
in an amendment to this Form 10-K or in the proxy statement for the 2016 annual meeting of stockholders, in either case,
to be filed within 120 days after December 31, 2015, and is incorporated by reference to this report.
Item 11. Executive Compensation
Information regarding executive compensation will be included in an amendment to this Form 10-K or in the
proxy statement for the 2016 annual meeting of stockholders and is incorporated by reference to this report.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information regarding beneficial ownership and management and related stockholder matters will be included
in an amendment to this Form 10-K or in the proxy statement for the 2016 annual meeting of stockholders and is
incorporated by reference to this report.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information regarding certain relationships and related transactions and director independence will be included
in an amendment to this Form 10-K or in the proxy statement for the 2016 annual meeting of stockholders and is
incorporated by reference to this report.
Item 14. Principal Accountant Fees and Services
Information regarding principal accounting fees and services will be included in an amendment to this
Form 10-K or in the proxy statement for the 2016 annual meeting of stockholders and is incorporated by reference to this
report.
80
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS
The following includes a description of the meanings of some of the oil and natural gas industry terms used in
this Annual Report on Form 10-K. The definitions “analogous reservoir,” “development costs,” “development project,”
“development well,” “economically producible,” “exploratory well,” “field,” “possible reserves,” “probable reserves,”
“production costs,” “proved area,” “reservoir,” “resources,” and “unproved properties” have been excerpted from the
applicable definitions contained in Rule 4-10(a) of Regulation S-X.
American Petroleum Institute (“API”) gravity: A system of classifying oil based on its specific gravity,
whereby the greater the gravity, the lighter the oil.
analogous reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid
properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more
advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation
of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a
reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation
(but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition;
(iii) similar geologic structure; and (iv) the same drive mechanism.
basin: A large depression on the earth’s surface in which sediments accumulate.
bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid
hydrocarbons.
bcf: One billion cubic feet of natural gas.
black oil: A quality of oil with an API gravity of 40° or less and with a gas-to-oil ratio of 500 cubic feet per
barrel or less.
bo: 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six
mcf of natural gas to one bo of oil.
boe/d: One boe per day.
bopd: One bo per day.
btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of
water by one degree Fahrenheit.
completion: The process of treating a drilled well followed by the installation of permanent equipment for the
production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
developed acreage: The number of acres that are allocated or assignable to producing wells or wells capable of
production.
development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting,
treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and
applicable operating costs of support equipment and facilities and other costs of development activities, are costs
incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose
of determining specific development drilling sites, clearing ground, draining, road building, and relating public roads,
gas lines, and power lines, to the extent necessary in developing the proved reserves; (ii) drill and equip development
wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well
81
equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, and install
production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production
storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (iv) provide
improved recovery systems.
development project: A development project is the means by which petroleum resources are brought to the
status of economically producible. As examples, the development of a single reservoir or field, an incremental
development in a producing field or the integrated development of a group of several fields and associated facilities with
a common ownership may constitute a development project.
development well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect
differences in the quality and/or location of oil or natural gas.
dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of such production would exceed production expenses and taxes.
economically producible: The term economically producible, as it relates to a resource, means a resource that
generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
exploitation: A development or other project that may target proven or unproven reserves (such as probable or
possible reserves), but that generally has a lower risk than that associated with exploration projects.
exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.
field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same
individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although
it may refer to both the surface and the underground productive formations.
gross acres or gross wells: The total acres or wells, as the case may be, in which we have working interest.
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.
independent exploration and production company: A company whose primary line of business is the
exploration and production of crude oil and natural gas.
LLS: Louisiana light sweet crude.
mbbl: One thousand bbl.
mbo: One thousand bo.
mboe: One thousand boe.
mcf: One thousand cubic feet of natural gas.
mmbo: One million bo.
mmbbl: One million bbl.
82
mmboe: One million boe.
mmbtu: One million British thermal units.
mmcf: One million cubic feet of natural gas.
net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership
percentage.
net production: Production that is owned by us less royalties and production due others.
net revenue interest: A working interest owner’s gross working interest in production less the royalty,
overriding royalty, production payment and net profits interests.
NG: Natural gas.
NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas
become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
operator: The individual or company responsible for the exploration and/or production of an oil or natural gas
well or lease.
possible reserves: Additional reserves that are less certain to be recovered than probable reserves.
probable reserves: Additional reserves that are less certain to be recovered than proved reserves but that, in
sum with proved reserves, are as likely as not to be recovered.
production costs: Costs incurred to operate and maintain wells and related equipment and facilities, including
depreciation and applicable operating costs of support equipment and facilities and other costs of operating and
maintaining those wells and related equipment and facilities.
productive well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to
produce at a reasonable rate of return.
proved area: The part of a property to which proved reserves have been specifically attributed.
proved developed reserves: Reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods.
proved oil and natural gas reserves: The estimated quantities of oil, natural gas and NGLs that geological and
engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known
reservoirs under existing economic and operating conditions.
proved undeveloped reserves: 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.
realized price: The cash market price less all expected quality, transportation and demand adjustments.
recompletion: The completion for production of an existing wellbore in another formation from that which the
well has been previously completed.
83
reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the
time of the reserve determination.
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.
resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring
accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered
unrecoverable. Resources include both discovered and undiscovered accumulations.
spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of
acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
standardized measure: The present value of estimated future after tax net revenue to be generated from the
production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and
costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted
at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative
transactions.
trend: A geographic area with hydrocarbon potential.
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.
unproved properties: Properties with no proved reserves.
volatile oil: A quality of oil with an API gravity greater than 40° and with a gas-to-oil ratio of greater than 500
cubic feet per barrel.
wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.
Also called well or borehole.
working interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill
for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling
and production operations.
workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate crude.
84
Item 15. Exhibits and Financial Statement Schedules
PART IV
a.
The following documents are filed as a part of this Annual Report on Form 10-K or incorporated
herein by reference:
(1)
Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2)
Financial Statement Schedules:
None.
(3)
Exhibits:
The following exhibits are filed or furnished with this Annual Report on Form 10-K or
incorporated by reference:
Exhibit No.
2.1
Description of Exhibit
Contribution, Conveyance and Assumption Agreement, dated as of December 19, 2011, by and
between Sanchez Energy Partners I, LP and Sanchez Energy Corporation (filed as Exhibit 2.1 to
the Company's Current Report on Form 8-K on December 23, 2011, and incorporated herein by
reference).
2.2
2.3 **
2.4 **
2.5 **
2.6 **
2.7 **
2.8 **
Contribution Agreement, dated November 8, 2011, by and between Ross Exploration, Inc. and
Sanchez Energy Corporation (filed as Exhibit 2.2 to Amendment No. 3 to the Company's
registration statement on Form S-1 (File. No. 333-176613) on November 25, 2011, and
incorporated herein by reference).
Purchase and Sale Agreement by and between Hess Corporation, as Seller, and Sanchez Energy
Corporation, as Buyer, dated as of March 18, 2013 (filed as Exhibit 2.1 to the Company's Current
Report on Form 8-K on June 3, 2013, and incorporated herein by reference).
Purchase and Sale Agreement by and between Altpoint Sanchez Holdings, LLC, as Seller, and
Sanchez Energy Corporation, as Buyer, dated as of August 7, 2013 (filed as Exhibit 2.1 to the
Company's Current Report on Form 8-K on August 13, 2013, and incorporated herein by
reference).
Purchase and Sale Agreement by and between Rock Oil Company, LLC, as Seller, and SN
Cotulla Assets, LLC, as Buyer, dated as of September 6, 2013 (filed as Exhibit 2.1 to the
Company's Current Report on Form 8-K on September 9, 2013, and incorporated herein by
reference).
Purchase and Sale Agreement by and between SWEPI LP and Shell Gulf of Mexico Inc., as
Sellers, and Sanchez Energy Corporation, as Buyer, dated May 21, 2014, effective as of
January 1, 2014 (filed as Exhibit 2.1 to the Company's Current Report on Form 8-K on May 22,
2014, and incorporated herein by reference).
Purchase and Sale Agreement, dated as of March 31, 2015, by and between SEP Holdings III,
LLC, on the one hand, and SEP Holdings IV, LLC and Sanchez Production Partners LP, on the
other hand (filed as Exhibit 2.1 to the Company's Current Report on Form 8-K on April 1, 2015,
and incorporated herein by reference).
Purchase and Sale Agreement, dated September 25, 2015, by and among Sanchez Energy
Corporation, SN Catarina, LLC and Sanchez Production Partners LP (previously filed as Exhibit
2.1 to the Company’s Current Report on Form 8-K on .September 29, 2015, and incorporated
herein by reference).
85
Exhibit No.
Description of Exhibit
2.9 (a)**
Amendment One to Purchase Agreement by and between Sanchez Energy Corporation and
Altpoint Sanchez Holdings, LLC, dated as of August 16, 2013.
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Certificate of Amendment of Amended and Restated Certificate of Incorporation of Sanchez
Energy Corporation (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K on May
28, 2013, and incorporated herein by reference).
Restated Certificate of Incorporation of Sanchez Energy Corporation, effective as of May 28,
2013 (filed as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q on November 8,
2013, and incorporated herein by reference).
Certificate of Designations of Series C Junior Participating Preferred Stock of Sanchez Energy
Corporation (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K on July 29,
2015, and incorporated herein by reference).
Amended and Restated Bylaws dated as of December 13, 2011 (filed as Exhibit 3.2 to the
Company's Current Report on Form 8-K on December 19, 2011, and incorporated herein by
reference).
Form of Common Stock Certificate (filed as Exhibit 4.1 to Amendment No. 3 to the Company's
registration statement on Form S-1 (File. No. 333-176613) on November 25, 2011, and
incorporated herein by reference).
Indenture, dated as of June 13, 2013, among Sanchez Energy Corporation, the subsidiary
guarantors named therein and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to
the Company's Current Report on Form 8- K on June 14, 2013, and incorporated herein by
reference).
First Supplemental Indenture, dated as of September 11, 2013, by and among Sanchez Energy
Corporation, SN TMS, LLC, the existing guarantors and U.S. Bank National Association as
trustee (filed as Exhibit 4.2 to the Company's Current Report on Form 8-K on September 19,
2013 and incorporated herein by reference).
Registration Rights Agreement, dated as of June 13, 2013, by and among Sanchez Energy
Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as
representative of the several initial purchasers named therein (filed as Exhibit 4.2 to the
Company's Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).
Registration Rights Agreement, dated as of September 18, 2013, by and among Sanchez Energy
Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit
Suisse Securities (USA), LLC, as representatives of the several initial purchasers named therein
(filed as Exhibit 4.3 to the Company's Current Report on Form 8-K on September 13, 2013 and
incorporated herein by reference).
Registration Rights Agreement, dated as of December 19, 2011, by and between Sanchez Energy
Corporation and Sanchez Energy Partners I, LP (filed as Exhibit 10.3 to the Company's Current
Report on Form 8-K on December 23, 2011, and incorporated herein by reference).
Second Supplemental Indenture, dated as of June 2, 2014, by and among Sanchez Energy
Corporation, SN Catarina, LLC, the existing guarantors and U.S. Bank National Association as
trustee (filed as Exhibit 4.6 to the Company's Registration Statement on Form S-4 on June 11,
2014, and incorporated herein by reference).
Indenture, dated as of June 27, 2014, among Sanchez Energy Corporation, the subsidiary
guarantors named therein and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to
the Company's Current Report on Form 8-K on July 2, 2014, and incorporated herein by
reference).
86
Exhibit No.
4.9
Registration Rights Agreement, dated as of June 27, 2014, by and among Sanchez Energy
Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as
representative of the several initial purchasers named therein (filed as Exhibit 4.2 to the
Company's Current Report on Form 8-K on July 2, 2014, and incorporated herein by reference).
Description of Exhibit
4.10
4.11
10.1
10.2
10.3 *
10.4 *
10.5 *
10.6 *
10.7 *
10.8 *
10.9 *
Registration Rights Agreement, dated as of September 12, 2014, by and among Sanchez Energy
Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit
Suisse Securities (USA), LLC, as representatives of the several initial purchasers named therein
(filed as Exhibit 4.2 to the Company's Current Report on Form 8-K on September 15, 2014, and
incorporated herein by reference).
Rights Plan dated as of July 28, 2015 between Sanchez Energy Corporation and Continental
Stock Transfer & Trust Company, as Rights Agent (including the form of Certificate of
Designations of Series C Junior Participating Preferred Stock attached thereto as Exhibit A, the
form of Right Certificate attached thereto as Exhibit B and the Summary of Rights attached
thereto as Exhibit C) (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K on July
29, 2015, and incorporated herein by reference).
Services Agreement, dated as of December 19, 2011, by and between Sanchez Oil & Gas
Corporation and Sanchez Energy Corporation (filed as Exhibit 10.1 to the Company's Current
Report on Form 8-K on December 23, 2011, and incorporated herein by reference).
Geophysical Seismic Data Use License Agreement, dated as of December 19, 2011, by and
among Sanchez Oil & Gas Corporation, Sanchez Energy Corporation, SEP Holdings III, LLC
and SN Marquis LLC (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on
December 23, 2011, and incorporated herein by reference).
Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy
Corporation and Antonio R. Sanchez, III (filed as Exhibit 10.4 to the Company's Current Report
on Form 8-K on December 23, 2011, and incorporated herein by reference).
Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy
Corporation and Michael G. Long (filed as Exhibit 10.5 to the Company's Current Report on
Form 8-K on December 23, 2011, and incorporated herein by reference).
Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy
Corporation and Gilbert A. Garcia (filed as Exhibit 10.6 to the Company's Current Report on
Form 8-K on December 23, 2011, and incorporated herein by reference).
Form of Restricted Stock Agreement for employees (filed as Exhibit 10.1 to the Company's
registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and incorporated
herein by reference).
Form of Restricted Stock Agreement for non-employee directors (filed as Exhibit 10.2 to the
Company's registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and
incorporated herein by reference).
Form of Restricted Stock Agreement for Antonio R. Sanchez, III (filed as Exhibit 10.3 to the
Company's registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and
incorporated herein by reference).
Indemnification Agreement, dated as of March 9, 2012, between Sanchez Energy Corporation
and Greg Colvin (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on
March 14, 2012, and incorporated herein by reference).
10.10 *
Indemnification Agreement, dated as of March 9, 2012, between Sanchez Energy Corporation
and Kirsten A. Hink (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on
March 14, 2012, and incorporated herein by reference).
87
Exhibit No.
10.11 *
Indemnification Agreement, dated as of November 27, 2012, between Sanchez Energy
Corporation and A.R. Sanchez, Jr. (filed as Exhibit 10.1 to the Company's Current Report on
Form 8-K on December 3, 2012, and incorporated herein by reference).
Description of Exhibit
10.12 *
10.13 *
10.14
10.15
10.16
10.17
10.18 *
10.19 *
10.20
Indemnification Agreement, dated as of November 27, 2012, between Sanchez Energy
Corporation and Alan G. Jackson (filed as Exhibit 10.2 to the Company's Current Report on
Form 8-K on December 3, 2012, and incorporated herein by reference).
Indemnification Agreement, dated as of March 4, 2014, between Sanchez Energy Corporation
and Christopher Heinson (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on
March 6, 2014, and incorporated herein by reference).
Purchase Agreement, dated June 13, 2014, by and among Sanchez Energy Corporation, the
subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit Suisse Securities
(USA), LLC, as representatives of the several initial purchasers named therein (filed as
Exhibit 10.1 to the Company's Current Report on Form 8-K on June 16, 2014, and incorporated
herein by reference).
Second Amended and Restated Credit Agreement, dated as of June 30, 2014, among Sanchez
Energy Corporation, as borrower, SEP Holdings III, LLC, SN Marquis LLC, SN Cotulla
Assets, LLC, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC, as loan parties, Royal
Bank of Canada, as administrative agent, Capital One, National Association, as syndication
agent, Compass Bank and SunTrust Bank as co-documentation agents, RBC Capital Markets as
sole lead arranger and sole book runner, and the lenders party thereto (filed as Exhibit 10.1 to the
Company's Current Report on Form 8-K on July 2, 2014, and incorporated herein by reference).
Purchase Agreement, dated September 9, 2014, by and among Sanchez Energy Corporation, the
subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit Suisse Securities
(USA), LLC, as representatives of the several initial purchasers named therein (filed as
Exhibit 10.1 to the Company's Current Report on Form 8-K on September 15, 2014, and
incorporated herein by reference).
First Amendment to Second Amended and Restated Credit Agreement, dated as of September 9,
2014, among Sanchez Energy Corporation, as borrower, SEP Holdings III, LLC, SN
Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC and SN
Catarina, LLC, as loan parties, Royal Bank of Canada, as administrative agent, Capital One,
National Association, as syndication agent, Compass Bank and SunTrust Bank as co-
documentation agents, RBC Capital Markets as sole lead arranger and sole book runner, and the
lenders party thereto (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on
September 15, 2014, and incorporated herein by reference).
Indemnification Agreement, dated as of November 4, 2014, between Sanchez Energy
Corporation and Sean Maher (filed as Exhibit 10.1 to the Company's Current Report on Form 8-
K on November 6, 2014, and incorporated herein by reference).
Voluntary Retirement Agreement and General Release, dated as of March 10, 2015, between
Sanchez Energy Corporation and Michael G. Long (filed as Exhibit 10.1 to the Company's
Current Report on Form 8-K on March 11, 2015, and incorporated herein by reference).
Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 31,
2015, by and among Sanchez Energy Corporation, as borrower, SN Marquis LLC, SN Cotulla
Assets LLC, SN Operating LLC, SN TMS, LLC, and SN Catarina LLC, as guarantors, Royal
Bank of Canada, as administrative agent, and the other agents and lenders party thereto (filed as
Exhibit 10.1 to the Company's Current Report on Form 8-K on April 1, 2015, and incorporated
herein by reference).
10.21 *
Indemnification Agreement, dated as of May 5, 2015, between Sanchez Energy Corporation and
Thomas Brian Carney (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on
May 8, 2015, and incorporated herein by reference).
88
Exhibit No.
10.22 *
Description of Exhibit
Indemnification Agreement, dated as of May 5, 2015, between Sanchez Energy Corporation and
G. Gleeson Van Riet (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on
May 8, 2015, and incorporated herein by reference).
10.23 *
10.24 *
10.25
10.26
10.27
10.28 *
16.1
Sanchez Energy Corporation Second Amended and Restated 2011 Long Term Incentive Plan
(filed as Exhibit 99.1 to the Company's Current Report on Form 8-K on May 27, 2015, and
incorporated herein by reference).
Indemnification Agreement, dated as of October 1, 2015, between Sanchez Energy Corporation
and Eduardo Sanchez (previously filed as Exhibit 10.1 to the Company’s Current Report on Form
8-K on October 6, 2015).
Third Amendment to Second Amended and Restated Credit Agreement, dated as of July 20,
2015, by and among Sanchez Energy Corporation, as borrower, SN Marquis LLC, SN Cotulla
Assets LLC, SN Operating LLC, SN TMS, LLC, and SN Catarina LLC, as guarantors, Royal
Bank of Canada, as administrative agent, and the other agents and lenders party thereto (filed as
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q on November 8, 2013, and
incorporated herein by reference).
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of September
29, 2015, by and among Sanchez Energy Corporation, as borrower, SN Marquis LLC, SN
Cotulla Assets LLC, SN Operating LLC, SN TMS, LLC, and SN Catarina LLC, as guarantors,
Royal Bank of Canada, as administrative agent, and the other agents and lenders party thereto
(filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q on November 8, 2013,
and incorporated herein by reference).
Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 30,
2015, by and among Sanchez Energy Corporation, as borrower, SEP Holdings III, LLC, SN
Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, and SN Catarina,
LLC, as guarantors, Royal Bank of Canada, as administrative agent, and the lenders party thereto
(filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on November 4, 2015, and
incorporated herein by reference).
Indemnification Agreement, dated as of December 14, 2015, between Sanchez Energy
Corporation and Gregory B. Kopel (filed as Exhibit 10.1 to the Company's Current Report on
Form 8-K on December 16, 2015, and incorporated herein by reference).
Letter from BDO USA, LLP, dated June 23, 2015, regarding the change in certifying accountant
(previously filed as Exhibit 16.1 to the Company’s Current Report on Form 8-K on June 23,
2015, and incorporated herein by reference).
21.1 (a)
List of Subsidiaries of Sanchez Energy Corporation.
23.1 (a)
Consent of KPMG LLP.
23.2 (a)
Consent of BDO USA, LLP.
23.3 (a)
Consent of Ryder Scott Company, L.P.
31.1 (a)
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2 (a)
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1 (b)
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2 (b)
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
99.1 (a)
Ryder Scott Company, L.P. Summary of December 31, 2015 Reserves.
101.INS (a)
XBRL Instance Document.
89
Exhibit No.
101.SCH (a)
XBRL Taxonomy Extension Schema Document.
Description of Exhibit
101.CAL (a)
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF (a)
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB (a)
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE (a)
XBRL Taxonomy Extension Presentation Linkbase Document.
(a) Filed herewith.
(b) Furnished herewith.
* Management contract or compensatory plan or arrangement.
** The exhibits and schedules to this agreement have been omitted form this filing pursuant to Item 601(b)(2) of
Regulation S-K. The Company will furnish copies of such omitted exhibits and schedules to the SEC upon request.
90
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 29, 2016.
SIGNATURES
SANCHEZ ENERGY CORPORATION
By:
/s/ ANTONIO R. SANCHEZ, III
Antonio R. Sanchez, III
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 and on the dates indicated:
Signature
Title
Date
/s/ ANTONIO R. SANCHEZ, III
Antonio R. Sanchez, III
/s/ G. GLEESON VAN RIET
G. Gleeson Van Riet
/s/ KIRSTEN A. HINK
Kirsten A. Hink
/s/ A. R. SANCHEZ, JR.
A. R. Sanchez, Jr.
Chief Executive Officer
February 29, 2016
Senior Vice President and Chief Financial Officer
February 29, 2016
Senior Vice President and Chief Accounting Officer
February 29, 2016
Executive Chairman of the Board of Directors
February 29, 2016
/s/ GILBERT A. GARCIA
Gilbert A. Garcia
Director
/s/ GREG COLVIN
Greg Colvin
Director
/s/ ALAN G. JACKSON
Alan G. Jackson
Director
/s/ SEAN M. MAHER
Sean M. Maher
Director
/s/ BRIAN CARNEY
Brian Carney
Director
91
February 29, 2016
February 29, 2016
February 29, 2016
February 29, 2016
February 29, 2016
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Sanchez Energy Corporation
Reports of Independent Registered Public Accounting Firms
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2015 and 2014
Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2015, 2014 and 2013
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013
Notes to Consolidated Financial Statements
Supplemental Quarterly Financial Results (Unaudited)
Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities
(Unaudited)
F-2
F-5
F-6
F-7
F-8
F-9
F-47
F-49
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Sanchez Energy Corporation:
We have audited the accompanying consolidated balance sheet of Sanchez Energy Corporation and subsidiaries
as of December 31, 2015 and the related consolidated statement of operations, stockholders’ equity, and cash flows for
the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Sanchez Energy Corporation and subsidiaries as of December 31, 2015 and the results of their
operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), Sanchez Energy Corporation’s internal control over financial reporting as of December 31, 2015, based
on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated February 29, 2016 expressed an unqualified
opinion on the effectiveness of the Company’s internal control over financial reporting.
As discussed in Note 2 to the consolidated financial statements, the company has changed its method of
accounting for the presentation of deferred tax assets and liabilities in 2015.
/s/ KPMG LLP
Houston, Texas
February 29, 2016
F-2
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Sanchez Energy Corporation:
We have audited Sanchez Energy Corporation ’s internal control over financial reporting as of December 31,
2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Sanchez Energy Corporation’s management is
responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining
an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit
also included performing such other procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with U.S. generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls
may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, Sanchez Energy Corporation maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheet of Sanchez Energy Corporation and subsidiaries as of December 31, 2015
and the related consolidated statement of operations, stockholders’ equity, and cash flows for the year then ended, and
our report dated February 29, 2016 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 29, 2016
F-3
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Sanchez Energy Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of Sanchez Energy Corporation as of December
31, 2014 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two
years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Sanchez Energy Corporation at December 31, 2014, and the results of its operations and its cash
flows for each of the two years in the period ended December 31, 2014, in conformity with accounting principles
generally accepted in the United States of America.
/s/ BDO USA, LLP
Houston, Texas
March 2, 2015
F-4
Sanchez Energy Corporation
Consolidated Balance Sheets
(in thousands, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents
Oil and natural gas receivables
Joint interest billings receivables
Accounts receivable - related entities
Fair value of derivative instruments
Other current assets
Total current assets
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties
Proved oil and natural gas properties
Total oil and natural gas properties
Less: Accumulated depreciation, depletion, amortization and impairment
Total oil and natural gas properties, net
Other assets:
Debt issuance costs, net
Fair value of derivative instruments
Deferred tax asset
Investments
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable
Other payables
Accrued liabilities:
Capital expenditures
Other
Deferred premium liability
Other current liabilities
Total current liabilities
Long term debt, net of premium and discount
Asset retirement obligations
Fair value of derivative instruments
Other liabilities
Total liabilities
Commitments and contingencies (Note 14)
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of December 31,
2015 and 2014 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 and 3,532,330 shares issued and
outstanding as of December 31, 2015 and 2014 of 6.500% Convertible Perpetual Preferred Stock, Series B, respectively)
Common stock ($0.01 par value, 150,000,000 shares authorized; 61,928,089 and 58,580,870 shares issued and outstanding as
of December 31, 2015 and 2014, respectively)
Additional paid-in capital
Accumulated deficit
Total stockholders' equity (deficit)
Total liabilities and stockholders' equity (deficit)
December 31,
2015
December 31,
2014
$
$
$
435,048
30,668
1,259
3,697
172,494
23,452
666,618
253,529
2,914,867
3,168,396
(2,412,293)
756,103
41,039
5,789
—
49,985
22,809
1,542,343
4,184
2,004
51,983
69,974
24,548
14,813
167,506
1,746,966
25,907
—
58,133
1,998,512
$
$
$
473,714
69,795
14,676
386
100,181
23,002
681,754
385,827
2,582,441
2,968,268
(706,590)
2,261,678
48,168
24,024
7,443
—
19,101
3,042,168
29,487
4,415
162,726
67,162
—
5,166
268,956
1,746,263
25,694
889
779
2,042,581
53
53
619
1,079,513
(1,536,354)
(456,169)
1,542,343
586
1,064,667
(65,719)
999,587
3,042,168
$
$
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Sanchez Energy Corporation
Consolidated Statements of Operations
(in thousands, except per share amounts)
REVENUES:
Oil sales
Natural gas liquid sales
Natural gas sales
Total revenues
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses
Production and ad valorem taxes
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
General and administrative (inclusive of stock-based compensation
expense of $14,831, $12,843, and $17,751 and for 2015, 2014, and 2013,
respectively)
Total operating costs and expenses
Operating income (loss)
Other income (expense):
Interest income and other income (expense)
Interest expense
Net gains (losses) on commodity derivatives
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Less:
Preferred stock dividends
Net income allocable to participating securities
Year Ended December 31,
2015
2014
2013
$
307,971 $ 538,887 $ 290,322
13,013
66,989
11,085
60,188
314,420
666,064
69,011
98,797
475,779
156,528
26,870
344,572
1,365,000
93,581
37,787
338,097
213,821
35,669
17,334
134,845
—
74,160
1,967,130
(1,491,351)
63,692
746,978
(80,914)
47,951
235,799
78,621
(2,163)
(126,399)
172,886
44,324
(1,447,027)
7,600
(1,454,627)
289
(89,800)
137,205
47,694
(33,220)
(11,429)
(21,791)
(16,008)
—
(33,590)
—
135
(30,934)
(16,938)
(47,737)
30,884
3,986
26,898
(18,525)
(364)
8,009
Net income (loss) attributable to common stockholders
$ (1,470,635) $ (55,381) $
Net income (loss) per common share - basic and diluted
Weighted average number of shares used to calculate net income (loss)
attributable to common stockholders - basic and diluted
$
(25.70) $
(1.06) $
0.22
57,229
52,338
36,379
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Sanchez Energy Corporation
Consolidated Statements of Stockholders’ Equity (Deficit)
(in thousands)
Series A
Preferred Stock
Series B
Preferred Stock
Common Stock
Shares
Amount
Shares
Amount
Shares
Amount
Additional
Paid-in
Capital
Accumulated
Deficit
BALANCE, December 31, 2012
3,000 $
Common shares issued, net of offering costs of $12,500
Issuance of Series B Preferred Stock, net of offering costs of $8,440
Preferred stock dividends
Purchase of oil and natural gas properties for common stock
Restricted stock awards, net of forfeitures
Purchases of common stock
Stock-based compensation
Net income
BALANCE, December 31, 2013
Common shares issued, net of offering costs of $8,731
Preferred stock dividends
Restricted stock awards, net of forfeitures
—
—
—
—
—
—
—
—
3,000 $
—
—
—
30
—
—
—
—
—
—
—
—
30
—
—
—
— $
—
4,500
—
—
—
—
—
—
4,500 $
—
—
—
—
—
45
—
—
—
—
—
—
45
—
—
—
Exchange of preferred stock for common stock
(1,161)
(12)
(968)
(10)
Stock-based compensation
Net loss
BALANCE, December 31, 2014
Common shares issued
Preferred stock dividends
Restricted stock awards, net of forfeitures
Exchange of preferred stock for common stock
Stock-based compensation
Net loss
—
—
1,839 $
—
—
—
—
—
—
BALANCE, December 31, 2015
1,839 $
—
—
18
—
—
—
—
—
—
18
—
—
3,532 $
—
—
—
(4)
—
—
3,528 $
—
—
35
—
—
—
—
—
—
35
33,762 $
338 $
385,086 $
11,040
111
241,309
—
—
343
1,276
(52)
—
—
—
—
3
13
(1)
—
—
216,515
—
7,517
(13)
(1,057)
17,751
—
46,369 $
464 $
867,108 $
5,000
—
1,673
5,539
—
—
50
—
17
55
—
—
167,469
—
(17)
17,264
12,843
—
58,581 $
586 $ 1,064,667 $
—
—
3,337
10
—
—
61,928 $
—
—
33
—
—
—
—
—
(33)
48
14,831
—
(18,711) $
(18,525)
—
—
—
—
—
—
—
—
—
26,898
(10,338) $
(16,293)
(17,297)
(21,791)
(65,719) $
—
(15,960)
Total
Stockholders'
Equity (Deficit)
366,743
241,420
216,560
(18,525)
7,520
—
(1,058)
17,751
26,898
857,309
167,519
(16,293)
—
—
12,843
(21,791)
999,587
—
(15,960)
—
—
14,831
(1,454,627)
(456,169)
—
(48)
—
(1,454,627)
The accompanying notes are an integral part of these consolidated financial statements.
F-7
619 $ 1,079,513 $ (1,536,354) $
Sanchez Energy Corporation
Consolidated Statements of Cash Flows
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
Stock-based compensation expense
Net (gains) losses on commodity derivative contracts
Net cash settlement received (paid) on commodity derivative contracts
Cash reimbursements received for operating leasehold improvements
Premiums paid on commodity derivative contracts
Loss on investment in SPP
Amortization of deferred gain on Western Catarina Midstream Divestiture
Amortization of debt issuance costs
Accretion of debt discount, net
Deferred taxes
Changes in operating assets and liabilities:
Accounts receivable
Other current assets
Accounts payable
Accounts receivable - related entities
Other payables
Accrued liabilities
Other current liabilities
Other liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties
Payments for other property and equipment
Proceeds from sale of oil and natural gas properties
Acquisition of oil and natural gas properties
Purchases of investments
Sale of investments
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings
Repayment of borrowings
Issuance of senior notes, net of premium and discount
Issuance of common stock
Issuance of preferred stock
Payments for offering costs
Financing costs
Preferred dividends paid
Purchase of common stock
Net cash provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations
Change in accrued capital expenditures
Capital expenditures in accounts payable
Purchase of oil and natural gas properties in exchange for common stock
Common stock issued in exchange for preferred stock
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes
Cash paid for interest
Year Ended December 31,
2015
2014
2013
$ (1,454,627) $
(21,791) $
26,898
344,572
1,365,000
14,831
(172,886)
131,123
2,648
(121)
935
(3,086)
7,529
703
7,443
60,480
(450)
(25,303)
(3,311)
(2,290)
2,813
(5,166)
1,188
272,025
338,097
213,821
12,843
(137,205)
5,600
—
(596)
—
—
9,002
755
(11,429)
(26,971)
(21,633)
(2,868)
(1,347)
1,522
51,590
5,166
779
415,335
134,845
—
17,751
16,938
(4,959)
—
(1,024)
—
—
6,902
258
3,986
(47,649)
(969)
32,355
(12,494)
2,286
14,137
—
—
189,261
(656,136)
(8,123)
427,571
(7,658)
(49,985)
—
(294,331)
(791,260)
(14,062)
—
(555,942)
—
—
(1,361,264)
(479,908)
(2,050)
—
(622,996)
—
11,591
(1,093,363)
—
—
—
—
—
—
(400)
(15,960)
—
(16,360)
100,000
(100,000)
1,152,250
176,250
—
(8,731)
(37,364)
(16,293)
—
1,266,112
236,000
(236,000)
593,000
253,920
225,000
(20,939)
(24,112)
(18,525)
(1,058)
1,007,286
(38,666)
473,714
435,048 $
320,183
153,531
473,714 $
103,184
50,347
153,531
$
$
(1,877) $
(110,744)
—
—
273
20,303 $
75,843
14,545
—
123,731
3,386
43,323
14,545
7,520
—
158
121,644 $
—
48,064 $
—
25,927
$
The accompanying notes are an integral part of these consolidated financial statements.
F-8
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Note 1. Organization and Business
Sanchez Energy Corporation (together with our consolidated subsidiaries, the “Company,” “we,” “our,” “us” or
similar terms) is an independent exploration and production company, formed in August 2011 as a Delaware corporation,
focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore
U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (“TMS”)
in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and
volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently
focused on the horizontal development of significant resource potential from the Eagle Ford Shale. We have included
definitions of some of the oil and natural gas terms used in this Annual Report on Form 10-K in the “Glossary of
Selected Oil and Natural Gas Terms.”
Note 2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The consolidated financial statements have been prepared in accordance with accounting principles generally
accepted in the United States of America (“U.S. GAAP”).
Recent Accounting Pronouncements
During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”,
which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be
classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current
and non-current portions. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim
periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim
or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a
retrospective basis. Adoption of this guidance affected the balance sheets as of December 31, 2014 as follows (in
thousands):
Decrease in Non-current assets of approximately $33,242
Decrease in Current liabilities of approximately $33,242
In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for
annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement
principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these
methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net
realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our
consolidated financial statements, but do not expect the impact to be material.
In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30):
Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of
debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting
Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the
balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a
separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after
December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is
permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not
F-9
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
expected to be material.
In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation
Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and
placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new
standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination
of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and
interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach,
with early adoption permitted. We are currently in the process of evaluating the impact of adoption of this guidance on
our consolidated financial statements, but do not expect the impact to be material.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This
guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts
with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This
new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The
new model will require revenue recognition to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new
guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not
permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the
cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact
of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.
Principles of Consolidation
The Company’s consolidated financial statements include the accounts of the Company and its subsidiaries. All
intercompany balances and transactions have been eliminated.
Use of Estimates
The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP, which
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 financial statements and the reported amounts of revenues
and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves
and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of
unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations,
accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual
results could differ materially from those estimates.
Cash Equivalents
Cash and cash equivalents consist primarily of cash on deposit, money market accounts and investment grade
commercial paper that are readily convertible into cash and purchased with original maturities of three months or less.
Oil and Natural Gas Receivables
The majority of the Company’s receivables arise from sales of oil, natural gas liquids (“NGLs”) or natural gas.
The Company does not have any off-balance-sheet credit exposure related to its customers. Receivables from the sale of
F-10
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
oil and natural gas are generally unsecured. Allowances for doubtful accounts are determined based on management’s
assessment of the creditworthiness of the customer. Receivables are considered past due if full payment is not received
by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all
the collection attempts have been exhausted. At December 31, 2015 and 2014, management believed that all balances
were fully collectible and no allowance for doubtful accounts was deemed necessary.
Oil and Natural Gas Properties
The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All
direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas
properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in
the amortization base and amortized to depletion expense using the units-of-production method. Depletion is calculated
based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas
properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the
relationship between costs and the estimated quantities of proved reserves.
Full Cost Ceiling Test—Capitalized costs (net of accumulated depreciation, depletion and amortization and
deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling
limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from
estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage
value) and estimated related future income taxes. In accordance with Securities and Exchange Commission (“SEC”)
rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as
the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to
the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or
location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the
cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the
excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center
ceiling. During the year ended December 31, 2015, the Company recorded a full cost ceiling test impairment after
income taxes of $1,365 million. During the year ended December 31, 2014, the Company recorded a full cost ceiling test
impairment before income taxes of $213.8 million. No impairment expense was recorded for the year ended December
31, 2013.
Depreciation, depletion, amortization and accretion—Depreciation, depletion, amortization and accretion
(“DD&A”) is provided using the units-of-production method based upon estimates of proved oil, NGL and natural gas
reserves with oil, NGL and natural gas production being converted to a common unit of measure based upon their
relative energy content. All capitalized costs of oil and natural gas properties, including the estimated future costs to
develop proved reserves, are amortized using the units-of-production method based on total proved reserves. Investments
in unproved properties and major development projects are not amortized until proved reserves associated with the
projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of
unproved properties is complete and when major development projects are evaluated, the costs previously excluded from
amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future
development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage
value.
In arriving at depletion rates under the units-of-production method, the quantities of recoverable oil and natural
gas reserves are established based on estimates made by internal and third party geologists and engineers, which require
F-11
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
significant judgment as does the projection of future production volumes and levels of future costs, including future
development costs. In addition, considerable judgment is necessary in determining when unproved properties become
impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may
have significant impact on the calculation of depletion and impairment expense.
Unproved Properties—Costs associated with unproved properties and properties under development are
excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated
with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base.
Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests
are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred
into the full cost pool subject to amortization when management determines that a project area has been evaluated
through drilling operations or a thorough geologic evaluation.
Based on management’s review and current operating plans, 11%, 9% and 11% of the unproved property
balance at December 31, 2015 is expected to be added to the amortization base during the years 2016, 2017 and 2018,
respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated
until after 2018, and represent leasehold interests that have expiration dates beginning in 2019 or leasehold interests that
are currently held by production.
The table below sets forth the cost of unproved properties excluded from the amortization base as of
December 31, 2015, and notes the year in which the associated costs were incurred (in thousands):
Leasehold acquisition costs
Exploration costs
Development costs
Total
Oil and Natural Gas Reserve Quantities
Prior to 2013
$
6,566 $
442
—
7,008 $
$
Year of Acquisition
2014
2013
78,944 $ 129,485 $
2,588
1,246
2,454
5,380
82,778 $ 137,319 $
Total
2015
17,211 $ 232,206
5,827
15,496
26,424 $ 253,529
343
8,870
The Company’s most significant estimates relate to its proved oil and natural gas reserves. The estimates of oil
and natural gas reserves as of December 31, 2015, 2014 and 2013 are based on reports prepared by a third party
engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”).
Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological
analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current
operating and economic parameters. Ryder Scott has historically prepared a reserve and economic evaluation of the
Company’s properties, utilizing information provided to it by management and other information available, including
information from the operators of the property.
The standards of the Financial Accounting Standards Board (“FASB”) and rules of the SEC permit the use of
new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead
to reliable conclusions about reserve volume estimates. These rules allow, but do not require, companies to disclose their
probable and possible reserves to investors in documents filed with the SEC.
F-12
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average
price based upon the prior 12-month first-day-of-the-month price rather than a period-end price.
Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations.
As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The
reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC
guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve
reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of
available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the
judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As
such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
Debt Issuance Costs
Debt issuance costs relating to long-term debt have been deferred and are being amortized and recorded as
interest expense over the term of the related debt instrument. During 2015, the Company capitalized approximately $0.4
million in costs associated with amending our Second Amended and Restated Agreement (as defined in Note 5, “Long-
Term Debt”). During 2014, the Company capitalized approximately $37.4 million in costs associated with the issuance
of the 6.125% Notes (as defined in Note 5, “Long-Term Debt”) and costs incurred to enter into the Second Amended and
Restated Credit Agreement. The Company expensed $3.9 million of debt issuance costs during 2014 in conjunction with
the termination of our senior unsecured Bridge Facility (as defined in Note 5, “Long-Term Debt”) obtained in connection
with the acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing
wells (the “Catarina Acquisition”). At December 31, 2015 and December 31, 2014, the Company had approximately
$41.0 million and $48.2 million, respectively, of debt issuance costs (net of accumulated amortization of $14.7 million
and $7.2 million, respectively) remaining that are being amortized over the terms of the respective debt.
Environmental Expenditures
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws
regulate the discharge of materials into the environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for
expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and
the costs can be reasonably estimated. Such liabilities are generally not discounted unless the timing of cash payments
for the liability or component is fixed or reliably determinable.
Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments,
litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and
the amount of the assessment and/or remediation can be reasonably estimated. Recoveries of environmental remediation
costs from third parties, which are probable of realization, are separately recorded and are not offset against the related
environmental liability.
Management believes the Company is currently in compliance with all applicable federal, state and local
regulations associated with its properties. Accordingly, no environmental remediation liability or loss associated with the
Company’s properties was recorded as of December 31, 2015 and 2014.
F-13
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Asset Retirement Obligations
Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to
plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in
accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of
plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. The inputs are
calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying
amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the
capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is
treated as an adjustment to the full cost pool.
To estimate the fair value of an asset retirement obligation, the Company employs a present value technique,
which reflects certain assumptions, including its credit-adjusted risk-free interest rate, inflation rate, the estimated
settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original
estimate of cash flows will result in change to the carrying amount of the liability.
Stock-Based Compensation
The Company records stock-based compensation expense for awards granted to its directors (for their services
as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718,
“Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date
fair value and recognized over the vesting period using the straight-line method.
Awards granted to employees of the Sanchez Group (as defined in Note 7, “Stock-Based Compensation”)
(including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in
exchange for services are considered awards to non-employees and the Company records stock-based compensation
expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to
Non-Employees.” For awards granted to non-employees, the Company records compensation expenses equal to the fair
value of the stock-based award at the measurement date, which is determined to be the earlier of the performance
commitment date or the service completion date. Compensation expense for unvested awards to non-employees is
revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are
measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the
services rendered.
For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair
value remeasured at each reporting period and recognized over the vesting period using the straight-line method.
Compensation expense for these awards will be revalued at each period end until vested.
Revenue Recognition
Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable
price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title
is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The
sales method of accounting is used for oil, NGL and natural gas sales. Oil and natural gas imbalances are generated on
properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less
than their respective entitled percentage. As of December 31, 2015, 2014 and 2013 there were no material oil and natural
gas imbalances.
F-14
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Sales to Major Customers
The Company’s oil, NGL and natural gas production was sold to certain customers representing 10% or more of
its total revenues for the years ended December 31, 2015, 2014 and 2013 as listed below:
Customer A
Customer B
Customer C
Customer D
2015 2014 2013
7% 23% 41%
0%
4%
4% 15% 23%
38% 37% 19%
14%
Production is normally sold to relatively few customers. Substantially all of the Company’s customers are
concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions,
the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers.
Management believes the loss of any of the Company’s major customers would not have a long-term material adverse
effect on the Company’s operations.
General and Administrative Expenses
On December 19, 2011, the Company entered into a services agreement and other related agreements with
Sanchez Oil & Gas Corporation (“SOG”), pursuant to which SOG (directly or through its subsidiaries) agreed to provide
the Company with the services and data that the Company believes are necessary to manage, operate and grow its
business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf. See detailed
discussion of the Company’s relationship with SOG in Note 9, “Related Party Transactions.”
Derivative Instruments
The Company utilizes derivative instruments in order to manage price risk associated with future crude oil and
natural gas production. Management sets and implements all of the hedging policies, including volumes, types of
instruments and counterparties, on a monthly basis. The Company recognizes all derivatives as either assets or liabilities,
measured at fair value, and recognizes changes in the fair value of derivatives in current earnings because it does not
designate its derivatives as cash flow hedges.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities
arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax
basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary difference and carryforwards are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the
amount more likely than not to be recovered.
Additionally, the Company is required to determine whether it is more likely than not (a likelihood of more than
50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation
processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is
F-15
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the
financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood
of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax
expense.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for
income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate
tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these
estimates, which could impact the Company’s financial position, results of operations and cash flows. The Company
does not have any material uncertain tax positions during the years ended December 31, 2015 or 2014.
Earnings per Share
Basic net income (loss) per common share are computed using the two-class method. The two-class method is
required for those entities that have participating securities. The two-class method is an earnings allocation formula that
determines net income (loss) per share for participating securities according to dividends declared (or accumulated) and
participation rights in undistributed earnings. The Company’s restricted shares of common stock (see Note 7,
“Stock-Based Compensation”) are participating securities under ASC 260, “Earnings per Share,” because they may
participate in undistributed earnings with common stock. Participating securities do not have a contractual obligation to
share in the Company’s losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating
securities.
Diluted net income (loss) per common share reflect the dilutive effects of the participating securities using the
two-class method or the treasury stock method, whichever is more dilutive. They also reflect the effects of the potential
conversion of the Company’s Series A and Series B Convertible Perpetual Preferred Stock using the if-converted
method, if the effect is dilutive.
Note 3. Acquisitions and Divestitures
Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic
805, “Business Combinations” (“ASC Topic 805”). A business combination may result in the recognition of a gain or
goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair
value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may
not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities
assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and
circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our
acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions.
Catarina Acquisition
On June 30, 2014, we completed the Catarina Acquisition for an aggregate adjusted purchase price of $557.1
million. The effective date of the transaction was January 1, 2014. The purchase price was funded with a portion of the
proceeds from the issuance of the $850 million senior unsecured 6.125% notes due 2023 (the ‘‘Original 6.125% Notes’’)
and cash on hand. The purchase price allocation for the Catarina Acquisition is preliminary and is subject to further
adjustments and the settlement of certain post-closing adjustments with the seller. The total purchase price was allocated
F-16
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in
thousands):
Proved oil and natural gas properties
Unproved properties
Other assets acquired
Fair value of assets acquired
Asset retirement obligations
Fair value of net assets acquired
Wycross Acquisition
$ 446,906
122,224
2,682
571,812
(14,723)
$ 557,089
On October 4, 2013, we completed our acquisition of contiguous acreage in McMullen County, Texas with 13
gross producing wells (the “Wycross Acquisition”) for an aggregate adjusted purchase price of $229.6 million. The
effective date of the transaction was July 1, 2013. The purchase price was funded with proceeds from the issuance of the
Additional 7.75% Notes (as defined in Note 5, “Long-Term Debt”), the issuance of 11,040,000 shares of common stock,
and cash on hand. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their
fair values on the date of acquisition as follows (in thousands):
Proved oil and natural gas properties
Unproved properties
Other assets acquired
Fair value of assets acquired
Asset retirement obligations
Other liabilities assumed
Fair value of net assets acquired
$ 215,265
13,095
1,523
229,883
(158)
(113)
$ 229,612
Cotulla Acquisition
On May 31, 2013, we completed our acquisition of acreage in Dimmit, Frio, LaSalle and Zavala Counties,
Texas with 53 gross producing wells (the “Cotulla Acquisition”) for an aggregate adjusted purchase price of $280.9
million. The effective date of the transaction was March 1, 2013.
The purchase price was funded with borrowings under the Company’s Amended and Restated Credit
Agreement (as defined in Note 5, “Long-Term Debt”), cash on hand, and proceeds from the Company’s private
placement of the Series B Convertible Perpetual Preferred Stock. The total purchase price was allocated to the assets
purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):
Proved oil and natural gas properties
Unproved properties
Fair value of assets acquired
Asset retirement obligations
Other liabilities assumed
Fair value of net assets acquired
$ 265,466
16,745
282,211
(1,138)
(190)
$ 280,883
F-17
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Palmetto Disposition
On March 31, 2015, we completed our disposition to a subsidiary of Sanchez Production Partners LP (“SPP”)
of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas (the “Palmetto
Disposition”) for an adjusted sales price of approximately $83.4 million. The effective date of the transaction was
January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and,
upon January 1 of each subsequent year after the closing, the purchaser’s working interest will automatically increase in
incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a
47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration
consisting of approximately $83.0 million (approximately $81.4 million as adjusted) cash and 1,052,632 common units
of SPP (the “SPP Common Units”) valued at approximately $2.0 million as of the date of the closing. These SPP
Common Units were later sold back to SPP in October 2015 as part of the Western Catarina Midstream Divestiture
described below. The Company did not record any gains or losses related to the Palmetto Disposition.
Western Catarina Midstream Divestiture
On October 14, 2015, the Company and SN Catarina, LLC (“SN Catarina”) completed the sale of SN Catarina’s
interests in Catarina Midstream, LLC, a wholly-owned subsidiary of SN Catarina (“Catarina Midstream”), which as of
the closing included certain midstream gathering lines and associated assets and interests located in Dimmit County and
Webb County, Texas and 105,263 SPP Common Units to SPP for an adjusted purchase price of $345.8 million in cash
(the “Western Catarina Midstream Divestiture”). In connection with the closing of the Western Catarina Midstream
Divestiture, SN Catarina and Catarina Midstream entered into a Firm Gathering and Processing Agreement (the
“Gathering Agreement”) on October 14, 2015 for an initial term of 15 years under which production from approximately
35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream. In
addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly
volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural
gas, subject to certain adjustments. SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel
for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each
case, subject to an annual escalation for a positive increase in the consumer price index. In addition, SN Catarina has,
under certain circumstances, a right of first refusal during the term of the agreement and afterwards with respect to
dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company recorded a deferred
gain of approximately $74.1 million as a result of Gathering Agreement being accounted for as an operating lease. This
deferred gain will be amortized straight-line over the firm commitment term of five years as an offset to the
transportation fees paid to SPP under the Gathering Agreement.
Pro Forma Operating Results (Unaudited)
The following unaudited pro forma combined results for the year ended December 31, 2014 reflects the
consolidated results of operations of the Company as if the Catarina Acquisition and related financing had occurred on
January 1, 2013. The pro forma information includes adjustments primarily for revenues and expenses from the acquired
properties, depreciation, depletion, amortization and accretion, impairment and interest expense and debt issuance cost
amortization for acquisition debt.
The unaudited pro forma combined financial statements give effect to the events set forth below:
• The Catarina Acquisition completed on June 30, 2014.
F-18
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
•
Issuance of the Original 6.125% Notes to finance a portion of the Catarina Acquisition, and the related
adjustments to interest expense:
Revenues
Net income (loss) attributable to common stockholders
Net income (loss) per common share, basic and diluted
Year Ended December 31,
2014
$
$
$
825,404
115,985
2.22
The unaudited pro forma combined financial information is for informational purposes only and is not intended
to represent or to be indicative of the combined results of operations that the Company would have reported had the
Catarina Acquisition and related financings been completed as of the date set forth in this unaudited pro forma combined
financial information and should not be taken as indicative of the Company’s future combined results of operations. The
actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a
number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma
combined financial information and actual results.
Post-Acquisition Operating Results
The amounts of revenue and excess of revenues over direct operating expenses included in the Company’s
consolidated statements of operations for the years ended December 31, 2015 and 2014, for the Catarina Acquisition are
shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad
valorem taxes (in thousands):
Revenues
Excess of revenues over direct operating expenses
Note 4. Cash and Cash Equivalents
Year Ended December 31,
2015
2014
$ 274,364 $ 134,885
96,225
$ 156,095 $
As of December 31, 2015 and 2014, cash and cash equivalents consisted of the following (in thousands):
Cash at banks
Money market funds
Total cash and cash equivalents
Note 5. Long-Term Debt
December 31, December 31,
$
$
2015
35,600 $
399,448
435,048 $
2014
73,528
400,186
473,714
Long-term debt as of December 31, 2015 consisted of $1.15 billion face value of 6.125% senior notes (the
“6.125% Notes,” consisting of $850 million in Original 6.125% Notes and $300 million in Additional 6.125% Notes
(defined below), which were issued at a premium to face value of $2.3 million) maturing on January 15, 2023, and $600
million principal amount of 7.75% senior notes (the “7.75% Notes,” consisting of $400 million in Original 7.75% Notes
F-19
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
(defined below) and $200 million in Additional 7.75% Notes, which were issued at a discount to face value of $7.0
million), maturing on June 15, 2021. As of December 31, 2015 and 2014 the Company’s long-term debt consisted of the
following:
Amount Outstanding
(in thousands) as of
December 31, December 31,
Second Amended and Restated Credit Agreement
7.75% Notes
6.125% Notes
Unamortized discount on Additional 7.75% Notes
Unamortized premium on Additional 6.125% Notes
Total long-term debt
$
2014
2015
— $
600,000
Interest Rate Maturity date
—
June 30, 2019
Variable
7.75%
600,000
June 15, 2021
6.125% January 15, 2023 1,150,000 1,150,000
1,750,000 1,750,000
(5,837)
2,100
$ 1,746,966 $ 1,746,263
(4,933)
1,899
The components of interest expense are (in thousands):
Interest on Senior Notes
Interest expense and commitment fees on credit agreement
Amortization of debt issuance costs
Amortization of discount on Additional 7.75% Notes
Amortization of premium on Additional 6.125% Notes
Total interest expense
Credit Facility
Year Ended December 31,
2015
2014
2013
$ (116,938) $ (78,479) $ (21,355)
(2,418)
(6,902)
(259)
—
$ (126,399) $ (89,800) $ (30,934)
(1,229)
(7,529)
(904)
201
(1,564)
(9,002)
(905)
150
Previous Credit Agreement: On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC (“SEP III”),
SN Marquis LLC (“SN Marquis”) and SN Cotulla Assets, LLC (“SN Cotulla”), collectively, as the borrowers, entered
into a revolving credit facility represented by a $500 million Amended and Restated Credit Agreement with Royal Bank
of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital
Markets as sole lead arranger and sole book runner and each of the other lenders party thereto (the “Amended and
Restated Credit Agreement”). The Amended and Restated Credit Agreement was to mature on May 31, 2018.
On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit Agreement.
The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million outstanding.
Second Amended and Restated Credit Agreement: On June 30, 2014, the Company, as borrower, and SEP III,
SN Marquis, SN Cotulla, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC as loan parties, entered into a
revolving credit facility represented by a $1.5 billion Second Amended and Restated Credit Agreement with Royal Bank
of Canada as the administrative agent, Capital One, National Association as the syndication agent, Compass Bank and
SunTrust Bank as co-documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the
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Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
lenders party thereto (the ‘‘Second Amended and Restated Credit Agreement’’). The Company has elected an available
commitment amount under the Second Amended and Restated Credit Agreement of $300 million. Additionally, the
Second Amended and Restated Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to
the lesser of $80 million and the total availability thereunder. As of December 31, 2015, there were no borrowings and
no letters of credit outstanding under the Second Amended and Restated Credit Agreement. Availability under the
Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable
borrowing base and aggregate elected commitment. The borrowing base under the Second Amended and Restated Credit
Agreement was set at $362.5 million upon issuance of the Additional 6.125% Notes and was increased to $650 million in
connection with the October 1, 2014 redetermination. However, the Company elected a commitment amount of $300
million and the Company retained the ability to increase the aggregate elected commitment up to the $650 million
approved borrowing base upon written notice from the Company and compliance with certain conditions, including the
consent of any lender whose elected commitment was increased. On March 31, 2015, pursuant to an amendment of the
Second Amended and Restated Credit Agreement, the borrowing base under such agreement was changed to $550
million, with the aggregate elected commitment amount of $300 million remaining unchanged. The borrowing base was
reduced as a result of several factors that included the decrease in reserve value from the decline in commodity prices
along with the reduction in reserves in connection with the Palmetto disposition discussed above partially offset by
underlying new reserve growth through drilling. On November 20, 2015, in connection with the October 1, 2015
redetermination, the borrowing base under the Second Amended and Restated Credit Agreement changed from $550
million to $500 million, with the aggregate elected commitment amount of $300 million remaining unchanged. The
borrowing base was further reduced to $425 million, without any change to the aggregate elected commitment amount,
by the Sixth Amendment (as defined below), as further discussed in Note 18, “Subsequent Events.” All of the aggregate
elected commitment amount was available for future revolver borrowings as of December 31, 2015.
The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the
Second Amended and Restated Credit Agreement can be subsequently redetermined up or down by the lenders based on,
among other things, their evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves.
Redeterminations of the borrowing base are scheduled to occur semi-annually on or before April 1 and October 1 of each
year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the
aggregate amount of the Company’s high yield debt and (from the date of the Sixth Amendment and as further discussed
in Note 18, “Subsequent Events”) second lien debt, other than second lien debt representing the payment of interest in
kind, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii)
interim redetermination at the election of the administrative agent at the direction of a majority of the credit exposures
or, if none, the elected commitments of the lenders, once between each scheduled redetermination and (iv) if the required
lenders so direct in connection with asset sales and swap terminations involving more than 10% of the value of the
proved developed oil and gas properties included in the most recent reserve report, reduction in an amount equal to the
borrowing base value, as determined by the administrative agent in its reasonable judgment, of the assets so sold and
swaps so terminated.
The Company’s obligations under the Second Amended and Restated Credit Agreement are secured by a first
priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries not
designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future
subsidiaries not designated as “unrestricted subsidiaries.”
The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the
Company’s existing and future subsidiaries not designated as “unrestricted subsidiaries.” At the Company’s election,
borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an
adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 0.50% to 2.50% for
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Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
alternate base rate borrowings and from 1.50% to 2.50% for eurodollar borrowings, depending on the utilization of the
borrowing base. Furthermore, the Company is also required to pay a commitment fee on the unused committed amount
at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the elected commitment.
The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and
events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments,
grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with
affiliates, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also
provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including
debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark-to-
market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million.
Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the
Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and
Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times, and (ii) senior secured debt to
consolidated last twelve months (“LTM”) EBITDA of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter.
On October 30, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders
party thereto entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement (the “Fifth
Amendment”) which Fifth Amendment, among other things, (1) amended the Second Amended and Restated Credit
Agreement and its exhibits and schedules to (a) update certain disclosures to be effective as of the date of the Fifth
Amendment, including (i) the organizational chart and subsidiary list in the schedules to the Second Amended and
Restated Credit Agreement to reflect the disposition of Catarina Midstream, LLC and (ii) the lists of marketing contracts
and swap agreements in the schedules to the Second Amended and Restated Credit Agreement; (b) modify certain
representations and the form of compliance certificate under the Second Amended and Restated Credit Agreement to
reference updated disclosures provided to the Administrative Agent pursuant to the terms of the Second Amended and
Restated Credit Agreement; (c) modify certain covenants to expressly (i) not require the Company to deliver fourth
quarter financial statements prior to the delivery of annual financial statements, (ii) not require that certain insurance
policies of the Loan Parties contain certain endorsements or loss payable provisions and (iii) permit the Loan Parties to
enter into certain leases; (d) permit the Loan Parties to deliver certain financial statements and related documents
required under the Second Amended and Restated Credit Agreement electronically and provide that, except in the case of
compliance certificates or for other deliveries to the Administrative Agent or a lender that requests physical delivery, any
such statements and documents that are filed with the SEC are deemed delivered when posted on the Company’s website
or other internet or intranet website to which each lender and the Administrative Agent have access; (e)(i) specifically
identify TPL South Texas Processing Company LP as the counterparty to the previously permitted Eagle Ford
Midstream JV Transaction (as defined in the Fifth Amendment), (ii) separately identify and permit the “Gathering JV”
component of such transaction and increase from $80 million to $115 million the permitted investment basket for
investments in the Eagle Ford Midstream JV Transaction generally, thereby making the entire existing $50 million
“other” permitted investment basket available for investments either in such transaction or other investments in
unrestricted subsidiaries of the Company and (iii) provide that none of the transactions comprising the Eagle Ford
Midstream JV Transaction shall be considered synthetic leases; (f) modify the change-in-business covenant to permit
unrestricted subsidiaries to make direct or indirect investments in the oil and gas industry and related businesses and
activities without restrictions on geography; (g) change the definition of “Material Adverse Effect” to (i) reference,
among other things, (x) the ability of the Loan Parties to perform their obligations under the Loan Documents (as defined
in the Second Amended and Restated Credit Agreement), rather than the ability of any Loan Party to perform any of its
obligations under any Loan Document, (y) the validity or enforceability of the Loan Documents, rather than the validity
or enforceability of any Loan Document, (z) the rights and remedies of or benefits available to the Administrative Agent,
any issuing bank or any lender under the Loan Documents, rather than under any Loan Document and (ii) provide that
F-22
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
general market or industry conditions, which do not affect the Company in a disproportionately adverse manner, shall
not constitute or be taken into account in determining whether there has been a “Material Adverse Effect”; and (h)
provide for other technical amendments, clarifications and corrections; and (2) waived any existing breaches of, and any
resulting defaults or events of defaults under the Second Amended and Restated Credit Agreement with respect to, the
Company’s covenants in the Second Amended and Restated Credit Agreement (a) to deliver fourth quarter financial
statements within 45 days after the end of such fiscal quarter; (b) to provide certain loss payable clauses or provisions
and endorsements with respect to certain insurance maintained by the Loan Parties; and (c) in respect of leases other than
capital leases and leases of hydrocarbon interests.
On January 22, 2016, the Company, the Guarantors, the Administrative Agent and the other agents and lenders
party thereto entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement (the “Sixth
Amendment”) to modify certain representations, covenants, exhibits and schedules and to waive any existing breaches
of, and any resulting defaults or events of default with respect to certain covenants of the Second Amended and Restated
Credit Agreement, all as further discussed in Note 18, “Subsequent Events.”
From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated
Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial
lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for
which they have received, or may in the future receive, customary fees and commissions for these transactions. As of
December 31, 2015, the Company was in compliance with the covenants of the Second Amended and Restated Credit
Agreement.
Bridge Commitment: In connection with the Catarina Acquisition we obtained a commitment (the “Bridge
Commitment”) from Royal Bank of Canada, RBC Capital Markets, Credit Suisse AG, Credit Suisse Securities (USA)
LLC, Capital One, National Association and SunTrust Bank to provide, arrange, bookrun and agent, as applicable, a
senior unsecured bridge facility (the “Bridge Facility”), in an aggregate amount up to $300 million (reduced by the
aggregate principal amount of the Additional 6.125% Notes). The Bridge Commitment was set to expire upon the
earliest to occur of (a) August 19, 2014, (b) the date of execution and delivery of definitive bridge documentation by us
and the lenders under the Bridge Facility or (c) the termination of the commitments by us. The Company terminated the
Bridge Commitment upon the execution of the Second Amended and Restated Credit Agreement on June 30, 2014 and
wrote off $3.9 million in costs associated with obtaining the Bridge Commitment to interest expense at that time.
7.75% Senior Notes Due 2021
On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the
Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest is payable on
each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after
deducting initial purchasers’ discounts and offering expenses, which we used to repay outstanding indebtedness under
our credit facilities. The Original 7.75% Notes are the senior unsecured obligations and are guaranteed on a joint and
several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries.
On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75%
senior notes due 2021 (the “Additional 7.75% Notes” and, together with the Original 7.75% Notes, the “7.75% Notes”)
in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net
proceeds of $188.8 million (after deducting the initial purchasers’ discounts and offering expenses of $4.2 million) from
the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013
through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional
F-23
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are
therefore treated as a single class of securities under the indenture. We used the net proceeds from the offering to
partially fund the Wycross Acquisition completed in October 2013, a portion of the 2013 and 2014 capital budgets, and
for general corporate purposes.
The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing
and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated
indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt
(including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing
such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint
and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the
extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and
unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future.
The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted
subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities;
(ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain
investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets;
(vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments
from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.
We have the option to redeem all or a portion of the 7.75% Notes, at any time on or after June 15, 2017 at the
applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75%
Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium,
together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June
15, 2017. In addition, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances
with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified
in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of
our assets.
On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75%
Notes that had been registered under the Securities Act of 1933, as amended (the ‘‘Securities Act’’), for an equal amount
of the 7.75% Notes that had not been registered under the Securities Act.
6.125% Senior Notes Due 2023
On June 27, 2014, the Company completed a private offering of the Original 6.125% Notes. Interest is payable
on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million,
after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the
$100 million in borrowings outstanding under its Amended and Restated Credit Agreement and to finance a portion of
the purchase price of the Catarina Acquisition. We used the remaining proceeds from the offering to fund a portion of the
remaining 2014 capital budget and for general corporate purposes. The Original 6.125% Notes are the senior unsecured
obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions,
substantially all of the Company’s existing and future subsidiaries.
On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125%
senior notes due 2023 (the ‘‘Additional 6.125% Notes’’ and, together with the Original 6.125% Notes, the 6.125% Notes
F-24
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
and, together with the 7.75% Notes, the ‘‘Senior Notes’’) in a private offering at an issue price of 100.75% of the
principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial
purchasers’ discounts, adding premiums to face value of $2.3 million and deducting estimated offering expenses of $6.4
million. The Company also received cash for accrued interest from June 27, 2014 through the date of the issuance of
$3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional
6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are therefore treated as a single
class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the
2014 capital budget and intend to use the remainder of the net proceeds to fund a portion of the 2015 capital budget, and
for general corporate purposes.
The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing
and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to the Company’s future
subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of the Company’s existing
and future secured debt (including under the Second Amended and Restated Credit Agreement) to the extent of the value
of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary
release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture
governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our
subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior
unsecured basis in the future.
The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted
subsidiaries’ ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities;
(ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain
investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets;
(vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments
from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.
The Company has the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15,
2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may
also redeem the 6.125% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a
make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at
any time prior to July 15, 2018. In addition, the Company may redeem up to 35% of the 6.125% Notes prior to July 15,
2017 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings
at the redemption price specified in the indenture. The Company may also be required to repurchase the 6.125% Notes
upon a change of control or if we sell certain Company assets.
On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the
6.125% Notes that had been registered under the Securities Act, for an equal amount of the 6.125% Notes that had not
been registered under the Securities Act.
Note 6. Stockholders’ Equity
Common Stock Offerings— On September 18, 2013, the Company completed a public offering of
11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the
underwriters’ overallotment option), at an issue price of $23.00 per share. The Company received net proceeds from this
offering of approximately $241.4 million, after deducting underwriters’ fees and offering expenses of approximately
F-25
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
$12.5 million. The Company used the net proceeds from the offering to partially fund the Wycross Acquisition
completed in October 2013 and a portion of the 2013 and 2014 capital budgets, and for general corporate purposes.
On June 12, 2014, the Company completed a public offering of 5,000,000 shares of common stock, at an issue
price of $35.25 per share. The Company received net proceeds from this offering of $167.5 million, after deducting
underwriters’ fees and offering expenses of $8.7 million. The Company used the net proceeds from the offering to
partially fund the 2014 capital budget and for general corporate purposes.
Series A Convertible Perpetual Preferred Stock Offering—On September 17, 2012, the Company completed a
private placement of 3,000,000 shares of Series A Convertible Perpetual Preferred Stock, which were sold to a group of
qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The issue
price of each share of the Series A Convertible Perpetual Preferred Stock was $50.00. The Company received net
proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and
commissions and offering costs of approximately $5.5 million.
Each share of Series A Convertible Perpetual Preferred Stock is convertible at any time at the option of the
holder thereof at an initial conversion rate of 2.325 shares of common stock per share of Series A Convertible Perpetual
Preferred Stock (which is equal to an initial conversion price of $21.51 per share of common stock) and is subject to
specified adjustments. Based on the initial conversion price, approximately 4,275,640 shares of common stock would be
issuable upon conversion of all of the outstanding shares of the Series A Convertible Perpetual Preferred Stock.
The annual dividend on each share of Series A Convertible Perpetual Preferred Stock is 4.875% on the
liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and
October 1, when, as and if declared by the Company’s Board of Directors (the “Board”). The Company may, at its
option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends
are cumulative, and as of December 31, 2015, all dividends accumulated through that date had been paid.
Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the
Series A Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or
more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of
the Series A Convertible Perpetual Preferred Stock and the holders of the Series B Convertible Perpetual Preferred
Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will
increase by that same number.
At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the
Series A Convertible Perpetual Preferred Stock to be automatically converted into common stock at the conversion price,
if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130%
of the conversion price for a specified period prior to the conversion.
If a holder elects to convert shares of Series A Convertible Perpetual Preferred Stock upon the occurrence of
certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above
the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Convertible
Perpetual Preferred Stock as a result of the fundamental change.
Series B Convertible Perpetual Preferred Stock Offering—On March 26, 2013, the Company completed a
private placement of 4,500,000 shares of Series B Convertible Perpetual Preferred Stock. The issue price of each share of
F-26
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
the Series B Convertible Perpetual Preferred Stock was $50.00. The Company received net proceeds from the private
placement of $216.6 million, after deducting placement agent’s fees and offering costs of $8.4 million.
Each share of Series B Convertible Perpetual Preferred Stock is convertible at any time at the option of the
holder thereof at an initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual
Preferred Stock (which is equal to an initial conversion price of approximately $21.40 per share of common stock) and is
subject to specified adjustments. Based on the initial conversion price, approximately 8,255,055 shares of common stock
would be issuable upon conversion of all of the outstanding shares of the Series B Convertible Perpetual Preferred Stock.
The annual dividend on each share of Series B Convertible Perpetual Preferred Stock is 6.500% on the
liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and
October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to
certain conditions, common stock or any combination thereof. Dividends are cumulative, and as of December 31, 2015,
all dividends accumulated through that date had been paid.
Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the
Series B Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or
more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of
the Series B Convertible Perpetual Preferred Stock and the holders of the Series A Convertible Perpetual Preferred
Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will
increase by that same number.
At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the
Series B Convertible Perpetual Preferred Stock to be automatically converted into common stock at the conversion price,
if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130%
of the conversion price for a specified period prior to the conversion.
If a holder elects to convert shares of Series B Convertible Perpetual Preferred Stock upon the occurrence of
certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above
the applicable conversion rate to compensate the holder for lost option time value of the shares of Series B Convertible
Perpetual Preferred Stock as a result of the fundamental change.
Preferred Stock Exchanges—On February 12, 2014 and February 13, 2014, the Company entered into exchange
agreements with certain holders (the ‘‘February 2014 Holders’’) of the Company’s Series A Convertible Perpetual
Preferred Stock, and of Series B Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to
exchange an aggregate of (i) 947,490 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to
any accrued and unpaid dividends thereon) for 2,425,574 shares of the Company’s common stock, and (ii) 756,850
shares of the Series B Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends
thereon) for 2,021,066 shares of common stock.
Additionally, on May 29, 2014, the Company entered into exchange agreements with certain holders (the ‘‘May
2014 Holders’’) of the Company’s Series A Convertible Perpetual Preferred Stock, and of Series B Convertible
Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 166,025 shares of
Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for
418,715 shares of the Company’s common stock, and (ii) 210,820 shares of the Series B Convertible Perpetual Preferred
Stock (and waive their rights to any accrued and unpaid dividends thereon) for 553,980 shares of common stock.
F-27
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Further, on August 28, 2014, the Company entered into exchange agreements with certain holders (the
‘‘August 2014 Holders,’’ and together with the May 2014 Holders and the February 2014 Holders, the ‘‘Holders’’) of
the Company’s Series A Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an
aggregate of 47,500 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and
unpaid dividends thereon) for 119,320 shares of the Company’s common stock.
Since the Holders were not entitled to any consideration over and above the initial conversion rates of 2.325 and
2.337 common shares for each preferred share exchanged for Series A Convertible Perpetual Preferred Stock and
Series B Convertible Perpetual Preferred Stock, respectively, any consideration is considered an inducement for the
Holders to convert earlier than the Company could have forced conversion.
The Company has determined the fair value of consideration transferred to the Holders and the fair value of
consideration transferrable pursuant to the original conversion terms. The $13.9 million, $3.1 million and $0.3 million
excess of the fair value of the shares of common stock issued over the carrying value of the Series A Preferred Stock and
Series B Preferred Stock redeemed in connection with the exchange agreements entered into in February, May and
August 2014, respectively, has been reflected as an additional preferred stock dividend, that is, as an increase in
accumulated deficit to arrive at net loss attributable to common shareholders in our condensed consolidated financial
statements.
Preferred Stock Conversion—On November 20, 2015, a holder of our Series B Convertible Perpetual Preferred
Stock exercised its right to convert 4,500 shares our Series B Convertible Perpetual Preferred Stock, at the prescribed
initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock, in
exchange for 10,517 shares of our common stock.
NOL Rights Plan—On July 28, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights
plan (the “Rights Plan”) with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, the Board
declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of our common stock. The
dividend was paid on August 10, 2015 to stockholders of record as of the close of business on August 7, 2015 (the “NOL
Record Date”). In addition, one Right automatically attaches to each share of common stock issued between the NOL Record
Date and such date as when the Rights become exercisable.
F-28
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Earnings (Loss) Per Share—The following table shows the computation of basic and diluted net income (loss)
per share for the years ended December 31, 2015, 2014, and 2013 (in thousands, except per share amounts):
Net income (loss)
Less:
Preferred stock dividends
Net loss allocable to participating securities(1)(2)
Net income (loss) attributable to common stockholders
Weighted average number of unrestricted outstanding common shares used to
calculate basic net earnings (loss) per share
Dilutive shares(3)(4)(5)
Denominator for diluted earnings (loss) per common share
Net income (loss) per common share - basic and diluted
Year Ended December 31,
2015
2014
2013
$ (1,454,627) $ (21,791) $ 26,898
(16,008)
—
(33,590)
—
$ (1,470,635) $ (55,381) $
(18,525)
(364)
8,009
57,229
—
57,229
(25.70) $
52,338
—
52,338
(1.06) $
36,379
—
36,379
0.22
$
(1) The Company's restricted shares of common stock are participating securities.
(2) For the years ended December 31, 2015 and 2014, no losses were allocated to participating restricted stock because
such securities do not have a contractual obligation to share in the Company's losses.
(3) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314
shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
(4) The year ended December 31, 2014 excludes 1,732,888 shares of weighted average restricted stock and 13,527,738
shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
(5) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225
shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual
Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for
diluted earnings per common share as these shares were anti-dilutive.
Note 7. Stock-Based Compensation
At the Annual Meeting of Stockholders of the Company held on May 21, 2015 (“2015 Annual Meeting”), the
Company’s stockholders approved the Sanchez Energy Corporation Second Amended and Restated 2011 Long Term
Incentive Plan (the “LTIP”). The Board had previously approved the LTIP on April 20, 2015, subject to stockholder
approval.
The Company’s directors and consultants as well as employees of SOG, Sanchez Energy Partners I, LP, and
their affiliates (excluding the Company) (collectively, the “Sanchez Group”) who provide services to the Company are
F-29
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
eligible to participate in the LTIP. Awards to participants may be made in the form of restricted shares, phantom shares,
share options, share appreciation rights and other share-based awards. The maximum number of shares that may be
delivered pursuant to the LTIP is limited to (i) 4,000,000 shares of common stock plus the number of shares of common
stock available under the predecessor to the LTIP on the record date of the 2015 Annual Meeting (the "Record Date") at
which the stockholders approved the LTIP as well as (ii) upon the issuance of additional shares of common stock from
time to time after the Record Date, an automatic increase of 15% of such issuance of additional shares of common stock,
unless the Board determines to increase the maximum number of shares of common stock by a lesser amount. Shares
withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an
award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of shares, the shares
subject to such award are then available for new awards under the LTIP. Shares delivered pursuant to awards under the
LTIP may be newly issued shares, shares acquired by the Company in the open market, shares acquired by the Company
from any other person, or any combination of the foregoing.
The LTIP is administered by the Board or the Compensation Committee as appointed by the Board. The Board
may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. The
Board has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the
number of shares that may be granted, subject to shareholder approval as may be required by the exchange upon which
the common shares are listed at that time, if any. No change may be made in any outstanding grant that would materially
reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by
the Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP,
awards then outstanding will continue pursuant to the terms of their grants.
During the year ended December 31, 2015, the Company issued 95,237 shares of restricted common stock
pursuant to the LTIP to five directors of the Company that vest within one year from the date of grant. Pursuant to ASC
718, stock-based compensation expense for these awards was based on their grant date fair values of $12.65 and $9.80
per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the
vesting period
The Company also issued approximately 3.4 million shares of restricted common stock pursuant to the LTIP to
certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services
agreement. Approximately 3.3 million shares of restricted common stock vest in equal annual amounts over a three-year
period and the remaining 0.1 million shares of restricted common stock vest in equal amounts over a five-year period.
During the year ended December 31, 2014, the Company issued 35,769 shares of restricted common stock
pursuant to the LTIP to four directors of the Company that vest within one year from the date of grant. Pursuant to ASC
718, stock-based compensation expense for these awards was based on their grant date fair values of $33.05 and $14.90
per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the
vesting period
The Company also issued approximately 2.0 million shares of restricted common stock pursuant to the LTIP to
certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services
agreement. Approximately 0.7 million shares of restricted common stock vest in equal annual amounts over a two-year
period and approximately 1.3 million shares of restricted common stock vest in equal annual amounts over a three-year
period.
During the year ended December 31, 2013, the Company issued 28,600 shares of restricted common stock
pursuant to the LTIP to three directors of the Company that vest one year from the date of grant. Pursuant to ASC 718,
F-30
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
stock-based compensation expense for these awards was based on their grant date fair value of $21.98 per share (the
closing sales price of the Company’s common stock on the grant date) and is being amortized over the one year vesting
period.
The Company also issued approximately 1.3 million shares of restricted common stock pursuant to the LTIP to
certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services
agreement. Approximately 0.5 million shares of restricted common stock vest in equal annual amounts over a two-year
period and approximately 0.8 million shares of restricted common stock vest in equal annual amounts over a three-year
period.
The Company recognized the following stock-based compensation expense (in thousands) which is included in
general and administrative expense in the consolidated statements of operations.
Restricted stock awards, directors
Restricted stock awards, non-employees
Total stock-based compensation expense
Year Ended December 31,
2015
2014
2013
$
$
917 $
13,914
14,831 $
802 $
12,041
12,843 $
655
17,096
17,751
Based on the $4.31 per share closing price of the Company’s common stock on December 31, 2015, there was
approximately $25.7 million of unrecognized compensation cost related to these non-vested restricted shares
outstanding. The cost is expected to be recognized over a weighted average period of approximately 1.84 years.
A summary of the status of the non-vested shares as of December 31, 2015 is presented below (in thousands,
except per share amounts):
Non-vested common stock at December 31, 2014
Granted
Vested
Forfeited
Non-vested common stock at December 31, 2015
Weighted
Number of Average
Aggregate
Intrinsic
Value
Shares
Fair Value (in thousands)
Weighted
Average
Remaining
Contractual
Life (Years)
2,718,286 $
3,482,337
(1,629,221)
(145,635)
4,425,767 $
22.98 $
9.03
22.56
21.39
12.21 $
62,477
31,452
(36,761)
(3,115)
54,053
1.84
As of December 31, 2015, approximately 5.2 million shares remain available for future issuance to participants.
F-31
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Note 8. Income Taxes
The components of the federal income tax provision for the years ended December 31, 2015, 2014 and 2013 are
(in thousands):
Year Ended December 31,
2015
2014
2013
Current expense as a result of current operations
Deferred expense (benefit) as a result of current operations
Increase (decrease) in valuation allowance
Net income tax expense (benefit)
$
(506,943)
514,385
— $
158 $
—
10,813
(6,827)
7,600 $ (11,429) $ 3,986
(11,429)
—
$
The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate
income tax rate of 35% and the Company’s effective tax rate is summarized as follows (in thousands):
Year Ended December 31,
2015
2014
2013
Income tax expense (benefit) at the federal statutory rate
Officers' compensation limitation
State Taxes (net of federal benefit)
Non-deductible general and administrative expenses
Percentage depletion carryforward
Differences between actual income taxes and
amounts estimated in prior years
Income tax expense (benefit)
Valuation allowance
Net income tax expense (benefit)
$ (506,460) $ (11,627) $ 10,809
—
—
4
—
1,328
(5,463)
309
—
—
—
231
(107)
3,501
(506,785)
514,385
—
10,813
(6,827)
7,600 $ (11,429) $ 3,986
74
(11,429)
—
$
F-32
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
The Company’s deferred tax position reflects the net tax effects of the temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting.
Significant components of the deferred tax assets and liabilities are as follows (in thousands):
As of December 31,
2014
2015
Deferred tax assets (liabilities):
Derivative assets
Depreciable, depletable property, plant and equipment
Share-based compensation
Revenue Recognition
Other
Federal net operating loss carryforward
State net operating loss carryforward
Deferred tax assets:
Valuation allowance
Total Deferred tax assets
$ (54,638) $ (43,087)
(178,164)
3,221
—
(300)
225,773
—
7,443
—
7,443
288,736
2,897
8,417
(535)
268,068
1,440
514,385
(514,385)
— $
$
As of December 31, 2015, the Company had NOLs of approximately $765.9 million which begin to expire in
2031. Additionally, the Company had net operating losses in the states of Montana, Mississippi, and Louisiana which
will begin to expire in 2018, 2033 and 2026, respectively.
Management assesses the available positive and negative evidence to estimate if sufficient future taxable
income will be generated to use the existing deferred tax assets. A significant piece of objective negative evidence
evaluated was the cumulative loss incurred over the three-year period ended December 31, 2015.
On the basis of this evaluation, as of December 31, 2015, a valuation allowance of approximately $514.4
million has been recorded to record only the portion of the deferred tax asset that is more likely than not to be realized.
The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all
available information obtained in future reporting periods.
During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”,
which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be
classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current
and non-current portions. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim
periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim
or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a
retrospective basis. Adoption of this guidance affected the balance sheets as of December 31, 2014 as follows (in
thousands):
Decrease in Non-current assets of approximately $33,242.
Decrease in Current liabilities of approximately $33,242.
The Company files income tax returns in the U.S. and various state jurisdictions. Sanchez is no longer subject to
examination by federal income tax authorities prior to 2012. State statues vary by jurisdiction.
F-33
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
As of December 31, 2015, 2014 and 2013, the Company had no material uncertain tax positions.
Note 9. Related Party Transactions
SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the
exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf
of its affiliates.
The Company does not have any employees. On December 19, 2011 it entered into a services agreement with
SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business
under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate
functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering,
lease and land administration, marketing, accounting, operational services, information technology services, compliance,
insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a
price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead
costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that
provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices,
including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s
behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance
by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other
fees or assessments imposed by law in connection with the provision of services to the Company (other than income,
franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege
taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third
party service providers.
Salaries and associated benefits of SOG employees and are allocated to the Company based on a fixed
percentage that is reviewed quarterly and adjusted, if needed, based on a detailed analysis of actual time spent by the
professional staff on Company projects and activities. General and administrative expenses such as office rent, utilities,
supplies and other overhead costs, are allocated on the same percentages as the SOG employee salaries. Expenses
allocated to the Company for general and administrative expenses for the years ended December 31, 2015, 2014 and
2013 are as follows (in thousands):
Year Ended December 31,
Administrative fees
Third-party expenses
Total included in general and administrative expenses
2013
2015
2014
$ 30,430 $ 33,610 $ 19,259
10,941
$ 35,857 $ 38,125 $ 30,200
5,427
4,515
As of December 31, 2015 and December 31, 2014, the Company had a net receivable from SOG and other
members of the Sanchez Group of $3.7 million and $0.4 million, respectively, which are reflected as “Accounts
receivable—related entities” and “Accounts payable—related entities,” respectively, in the consolidated balance sheets.
The net receivable as of December 31, 2015 and December 31, 2014 consists primarily of advances paid related to
leasehold and other costs paid to SOG. In addition, the net receivable as of December 31, 2015 and December 31, 2014
includes approximately $0.7 million and $0.1 million, respectively, of net receivable from Sanchez Resources, LLC
(“Sanchez Resources”).
F-34
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
As of December 31, 2015, the Company had a net payable to SPP of approximately $4.4 million that consists
primarily of the December accrual for fees associated with the Gathering Agreement (see Note 3, “Acquisitions and
Divestitures” for further discussion), which is reflected in the “Other Accrued liabilities” account on the consolidated
balance sheets.
Palmetto Disposition
On March 31, 2015, we completed the Palmetto Disposition discussed above to a subsidiary of SPP, which is a
related party (see Note 3, “Acquisitions and Divestitures”).
Western Catarina Midstream Divestiture
On October 14, 2015, we completed the Western Catarina Midstream Divestiture discussed above to SPP,
which is a related party (see Note 3, “Acquisitions and Divestitures”).
TMS Asset Purchase
In August 2013, we acquired rights to approximately 40,000 net undeveloped acres in what we believe to be the
core of the TMS (the “TMS Transaction”) for cash and shares of our common stock. In connection with the TMS
Transaction, we established an Area of Mutual Interest (‘‘AMI’’) in the TMS with SR Acquisition I, LLC (‘‘SR’’), a
subsidiary of our affiliate Sanchez Resources, which transaction included a carry on drilling costs for up to 6 gross (3
net) wells. Sanchez Resources is indirectly owned, in part, by our Chief Executive Officer and the Executive Chairman
of the Board, who each also serve on our Board. Eduardo Sanchez, Patricio Sanchez and Ana Lee Sanchez Jacobs, each
an immediate family member of our Chief Executive Officer and the Executive Chairman of our Board, collectively,
either directly or indirectly, own a majority of the equity interests of Sanchez Resources. Sanchez Resources is managed
by Eduardo Sanchez, who is the brother of our Chief Executive Officer and the son of our Executive Chairman of the
Board. In addition, Eduardo Sanchez was named President of Sanchez Energy, effective as of October 1, 2015.
As part of the transaction, we acquired our working interests in the AMI owned at closing from three sellers
(two third parties and one related party of the Company, SR) resulting in our owning an undivided 50% working interest
across the AMI through the TMS.
Total consideration for the transactions consisted of approximately $70 million in cash and the issuance of
342,760 common shares of the Company, valued at approximately $7.5 million. The total cash consideration provided to
SR, an affiliate of the Company, was $14.4 million, before consideration of any well carries. The acquisitions were
accounted for as the purchase of assets at cost at the acquisition date. We also committed, as a part of the total
consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the
AMI (the “Initial Well Carry”) with an option to drill an additional 6 gross (3 net) TMS wells (“Additional Wells”)
within the AMI. In August 2015, after completing the Initial Well Carry, the Company signed an agreement with SR
whereby the Company paid SR approximately $8 million in lieu of drilling the remaining two Additional Wells (the
“Buyout Agreement”). The Buyout Agreement stipulates that SN has earned full rights to all acreage stated in the TMS
Transaction and effectively terminates any future well carry commitments.
F-35
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Note 10. Derivative Instruments
To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the
economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of
its projected oil and natural gas production through various transactions that fix or, through options, modify the future
prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its
production and pay a variable market price to the contract counterparty. In addition, the Company enters into option
transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. Additionally, the
Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays
the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and
natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the
Company’s intention to enter into derivative contracts for speculative trading purposes.
Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the consolidated
balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement
date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset.
Changes in the derivatives’ fair values are recognized currently in earnings since the Company has elected not to
designate its current derivative contracts as hedges.
As of December 31, 2015, the Company had the following NYMEX WTI crude oil swaps covering anticipated
future production:
Calendar Year
2016
Volumes
(Bbls)
Average Price
per Bbl
2,562,000 $
70.11 $
Price Range
per Bbl
62.00 - $
80.15
As of December 31, 2015, the Company had the following NYMEX WTI crude oil puts covering anticipated
future production:
Calendar Year
Volumes (Bbls)
Put Price per Bbl
Put Price Range per Bbl
2016
4,026,000 $
60.00
$
60.00 - $
60.00
As of December 31, 2015, the Company had the following NYMEX Henry Hub natural gas swaps covering
anticipated future production:
Calendar Year
2016
2017
Volumes
(Mmbtu)
Average Price
per Mmbtu
36,290,000 $
27,945,000 $
3.12 $
3.00
Price Range
per Mmbtu
2.54 - $
2.89 $
3.92
3.65
F-36
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity
derivatives for the years ended December 31, 2015, 2014, and 2013 (in thousands):
Year Ended December 31,
Beginning fair value of commodity derivatives
Net gains on crude oil derivatives
Net gains on natural gas derivatives
Net settlements on derivative contracts:
Crude oil
Natural gas
Net premiums on derivative contracts:
Crude oil
Ending fair value of commodity derivatives
Balance Sheet Presentation
2015
2014
$ 123,316 $ (3,397) $
170,592
26,843
115,602
21,603
2013
2,145
(16,891)
(47)
(123,946)
(18,522)
(4,503)
(1,097)
5,755
32
5,609
$ 178,283 $ 123,316 $ (3,397)
(4,892)
—
The Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the
consolidated balance sheets. The following information summarizes the gross fair values of derivative instruments,
presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets (in
thousands):
Gross Amount Offset in the
of Recognized Consolidated
December 31, 2015
Gross Amounts Net Amounts
Presented in the
Consolidated
Balance Sheets Balance Sheets
Assets
Offsetting Derivative Assets:
Current asset
Long-term asset
Total asset
Offsetting Derivative Liabilities:
Current liability
Long-term liability
Total liability
$ 172,518 $
5,821
$ 178,339 $
(24) $
(32)
(56) $
172,494
5,789
178,283
$
$
(24) $
(32)
(56) $
24 $
32
56 $
—
—
—
F-37
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Offsetting Derivative Assets:
Current asset
Long-term asset
Total asset
Offsetting Derivative Liabilities:
Current liability
Long-term liability
Total liability
Note 11. Fair Value of Financial Instruments
Gross Amount Offset in the
of Recognized Consolidated
December 31, 2014
Gross Amounts Net Amounts
Presented in the
Consolidated
Assets
Balance Sheets Balance Sheets
$ 194,953 $
24,024
$ 218,977 $
(94,772) $
—
(94,772) $
100,181
24,024
124,205
$
$
(94,772) $
(889)
(95,661) $
94,772 $
—
94,772 $
—
(889)
(889)
Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which
prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received
upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date. Fair value measurements are classified and disclosed in one of the following categories:
Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement
date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for
the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing
basis.
Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either
directly or indirectly, for substantially the full term of the asset or liability. This category includes those
derivative instruments that can be valued using observable market data. Substantially all of these inputs are
observable in the marketplace throughout the term of the derivative instrument, can be derived from observable
data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair
value measurement and less observable from objective sources (i.e. supported by little or no market activity).
The valuation models used to value derivatives associated with the Company’s oil and natural gas production
are primarily industry standard models that consider various inputs including: (a) quoted forward prices for
commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as
well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness
of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these
assets and liabilities as Level 2.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value
measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value
hierarchy levels.
F-38
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Fair Value on a Recurring Basis
The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and
liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 (in thousands):
Active Market
As of December 31, 2015
Cash and cash equivalents:
Money market funds
Oil derivative instruments:
Swaps
Puts
Gas derivative instruments:
Swaps
Total
Cash and cash equivalents:
Money market funds
Oil derivative instruments:
Swaps
Enhanced Swaps
Three-way collars
Gas derivative instruments:
Swaps
Enhanced Swaps
Three-way collars
Total
for Identical Observable Unobservable
Inputs
(Level 2)
Inputs
(Level 3)
Assets
(Level 1)
Total
Carrying
Value
$ 399,448 $
— $
— $ 399,448
—
—
72,887
76,583
—
—
72,887
76,583
—
28,813
$ 399,448 $ 178,283 $
—
28,813
— $ 577,731
As of December 31, 2014
Active Market
for Identical Observable Unobservable
Assets
Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
Carrying
Value
$ 400,186 $
— $
— $ 400,186
—
—
—
33,975
—
—
—
44,586
24,264
33,975
44,586
24,264
—
—
—
13,818
—
—
$ 400,186 $ 47,793 $
13,818
—
5,193
5,193
1,480
1,480
75,523 $ 523,502
Financial Instruments: The Level 1 instruments presented in the tables above consist of money market funds
included in cash and cash equivalents on the Company’s consolidated balance sheets as of December 31, 2015 and 2014.
The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial
institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money
market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active
markets for the underlying investments.
F-39
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
The Company’s derivative instruments, which consist of swaps, enhanced swaps, collars and puts, are classified
as Level 2 as of December 31, 2015, and either Level 2 or Level 3 as of December 31, 2014, in the table above. The fair
values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily
available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes.
Since swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level
2. As of December 31, 2014, the Company’s enhanced swaps, puts, collars and three-way collars included some level of
unobservable inputs, such as volatility curves, and were therefore classified as Level 3. As of December 31, 2015, the
Company believes that substantially all of the inputs required to calculate the fair value of puts and swaps observable in
the marketplace throughout the term of these derivative instruments or supported by observable levels at which
transactions are executed in the marketplace, and are therefore classified as Level 2. Derivative instruments are also
subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in
the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair
values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead
to corresponding changes in the fair value measurement of the Company’s derivative instruments.
There were no derivative instruments classified as Level 3 as of December 31, 2015. The fair values of the
Company’s derivative instruments classified as Level 3 as of December 31, 2014 and 2013 were $75.5 million and ($0.5)
million, respectively. The significant unobservable inputs for Level 3 contracts as of December 31, 2014 include
unpublished forward prices of commodities, market volatility and credit risk of counterparties
The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative
instruments classified as Level 3 in the fair value hierarchy (in thousands):
Beginning balance
Total gains (losses) included in earnings
Net settlements on derivative contracts(1)
Derivative contracts transferred to Level 2
Ending balance
2015
2013
(Level 3)
Year Ended December 31,
2014
(519) $ 3,015
(8,947)
5,413
—
(519)
$ 75,523 $
418
(14,277)
(61,664)
$
81,404
(5,362)
—
— $ 75,523 $
Gains (losses) included in earnings related to derivatives still held as of December
31, 2015, 2014, and 2013
$
(940) $ 76,760 $ (6,304)
(1) Includes ($12,919) of net settlements in Level 2 that were transferred from Level 3 during 2015.
Fair Value on a Non-Recurring Basis
The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair
value on a non-recurring basis. Fair value measurements of assets acquired and liabilities assumed in business
combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value
of acquired properties is based on market and cost approaches. Our purchase price allocations for the Catarina, Wycross
and Cotulla Acquisitions are presented in Note 3, “Acquisitions and Divestitures.” Liabilities assumed include asset
retirement obligations existing at the date of acquisition. Asset retirement obligation estimates are derived from historical
costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to
support the assumptions, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and
ending balances of the Company’s asset retirement obligations is presented in Note 12, “Asset Retirement Obligations.”
F-40
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
In connection with the exchange agreements entered into in February, May and August 2014 by the Company
with certain holders of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible
Perpetual Preferred Stock, the Company issued common stock according to the conversion rate pursuant to each
agreement and additional shares to induce the holders of the preferred stock to convert prior to the date the Company
could mandate conversion. In addition, on November 20, 2015, a holder of our Series B Convertible Perpetual Preferred
Stock exercised its right to convert 4,500 shares our Series B Convertible Perpetual Preferred Stock, at the prescribed
initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock, in
exchange for 10,517 shares of our common stock. The fair value of the common stock issued is based on the price of the
Company’s common stock on the date of issuance. As there is an active market for the Company’s common stock, the
Company has designated this fair value measurement as Level 1. A detailed description of the Company’s common stock
and preferred stock issuances and redemptions is presented in Note 6, ‘‘Stockholders’ Equity.’’
Fair Value of Other Financial Instruments
Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payable and
accrued liabilities and long-term debt. The carrying amounts of our oil and natural gas receivables, accounts payable and
accrued liabilities approximate fair value due to the highly liquid nature of these short term instruments. The registered
7.75% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated
fair value of the 7.75% Notes was $366 million as of December 31, 2015, and was calculated using quoted market prices
based on trades of such debt as of that date. The Company uses a market approach to determine fair value of its
unregistered 6.125% Notes using observable market data. However, as the market for the 6.125% Notes is far less active
than that of the 7.75% Notes, the Company also uses comparable market values for similar instruments, which results in
a Level 2 fair value measurement. The estimated fair value of the 6.125% Notes was $615.3 million as of December 31,
2015.
Note 12. Asset Retirement Obligations
The Company’s asset retirement obligations represent the present value of the estimated cash flows expected to
be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive
lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes
in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions
of estimated inflation rates, changes in property lives, and the expected timing of settlement. The changes in the asset
retirement obligation for the years ended December 31, 2015 and 2014 were as follows (in thousands):
Abandonment liability as of January 1,
Liabilities incurred during period
Acquisitions
Divestitures
Revisions
Accretion expense
Abandonment liability as of December 31,
2015
2014
$
25,694 $
6,021
—
(379)
(7,623)
2,194
$
25,907 $
4,130
3,922
14,723
—
1,658
1,261
25,694
F-41
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
Note 13. Accrued Liabilities
The following information summarizes accrued liabilities as of December 31, 2015 and 2014 (in thousands):
Capital expenditures
Other:
General and administrative costs
Production taxes
Ad valorem taxes
Lease operating expenses
Interest payable
Leasehold improvements
Total accrued liabilities
Note 14. Commitments and Contingencies
As of December 31,
2015
2014
$ 162,726
51,983
$
5,214
2,532
886
27,077
34,265
—
830
3,137
1,994
22,354
37,743
1,104
$ 121,957 $ 229,888
From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. We
are not aware of any material governmental proceedings against us or contemplated to be brought against us.
On December 4, 13 and 16, 2013, three derivative actions were filed in the Court of Chancery of the State of
Delaware against the Company, certain of its officers and directors, Sanchez Resources, Altpoint Capital Partners LLC
and Altpoint Sanchez Holdings, LLC (Friedman v. A.R. Sanchez, Jr. et al., No. 9158; City of Roseville Employees’
Retirement System v. A.R. Sanchez, Jr. et al., No. 9132; and Delaware County Employees Retirement Fund v. A.R.
Sanchez, Jr. et al., No. 9165 (collectively, the ‘‘Consolidated Derivative Actions’’)).
On December 20, 2013, the Consolidated Derivative Actions were consolidated, co-lead counsel for the
plaintiffs was appointed and the plaintiffs were ordered to file an amended consolidated complaint (In re Sanchez Energy
Derivative Litigation, Consolidated C.A. No. 9132-VCG, hereinafter, the “Delaware Derivative Action”). On January
28, 2014, a verified consolidated stockholder derivative complaint was filed. The Consolidated Derivative Actions
concern the Company’s purchase of working interests in the TMS from Sanchez Resources. Plaintiffs alleged breaches
of fiduciary duty against the individual defendants as directors of the Company; breaches of fiduciary duty against
Antonio R. Sanchez, III as an executive director of the Company; aiding and abetting breaches of fiduciary duty against
Sanchez Resources, Eduardo Sanchez, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC; and unjust
enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. All of the defendants filed a motion to dismiss on
April 1, 2014. Briefing concerning the motions to dismiss concluded on June 27, 2014. A hearing was held on August
11, 2014, on the motions to dismiss, and the court subsequently granted the motions to dismiss. The plaintiffs appealed
the case to the Delaware Supreme Court for which the parties fully briefed the appeal and provided oral argument. On
October 2, 2015, the Delaware Supreme Court reversed the motions to dismiss and remanded the case to the Court of
Chancery of the State of Delaware. No scheduling order for the matter has been set at this time. The Company is unable
to reasonably predict an outcome or to reasonably estimate a range of possible loss.
On January 9, 2014, a derivative action was filed in 333rd district court in Harris County, Texas against the
Company and certain of its officers and directors, styled Martin v. Sanchez, No. 2014-01028 (333rd Dist. Harris County,
Texas). The complaint alleged a breach of fiduciary duty, corporate waste and unjust enrichment against various officers
and directors. No action has been taken to date and damages are unspecified. On March 14, 2014, this action was stayed
F-42
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
following a ruling on the motion to dismiss in the Delaware Derivative Action. After the motions to dismiss were
granted in the Delaware Derivative Action, the parties entered into another agreed stay pending the appeal of the
Delaware Derivative Action to the Delaware Supreme Court. This stay was entered by the court on February 5,
2015. Since the Delaware Supreme Court has ruled on the appeal, the parties agreed to another stay for 60 days
following the completion of fact discovery in the Delaware Derivative Action. This action is in its preliminary stages,
and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss.
Defendants believe that the allegations contained in the matters described above are without merit and intend to
vigorously defend themselves against the claims raised.
In connection with the Catarina Acquisition, the 77,000 acres of undeveloped acreage that were included in the
acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each
annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120 - day period in order to
maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given
annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for
well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty
payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the
minimum number of wells required to maintain access to such undeveloped acreage.
As of December 31, 2015, the Company had $265.4 million in lease payment obligations that satisfy operating
lease criteria. These obligations include: (i) $200.7 million in payments due with respect to firm commitment of oil and
natural gas volumes under the Gathering Agreement contract signed with SPP as part of the Western Catarina Midstream
Divestiture that commenced on October 14, 2015 and continues until October 13, 2020, (ii) $50.8 million for a new
corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (iii) $7.1
million for a ground lease agreement for land owned by the Calhoun Port Authority that commenced during the third
quarter of 2014 and has an expiration date in August 2024 and (iv) $6.8 million for a 10 year acreage lease agreement for
a promotional ranch managed by the Company in Kenedy County, Texas. This acreage lease agreement includes a
contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the
ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the
lease term.
The Company’s ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the
Company to the lessor in addition to a $1 million termination payment. The Company has the right to terminate its lease
obligation for its acreage in Kenedy County, Texas at any time without penalty with six months advanced written notice
and payment of any accrued leasehold expenses.
On October 2, 2015, the Company, through SN Midstream LLC, a wholly-owned subsidiary of the Company
(“SN Midstream”), entered into joint venture agreements with an affiliate of Targa to construct a new cryogenic natural
gas processing plant (the “Processing Plant”) and associated high pressure gathering pipelines near the Company’s
Catarina asset in the Eagle Ford Shale. In connection with the Processing Plant joint venture agreement, SN Midstream
has committed to invest approximately $80 million and receive a 50% ownership interest in the joint venture owning the
Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint
venture agreement, SN Midstream has committed to invest approximately $35 million and receive a 50% ownership
interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering
system to the Processing Plant. Construction on the gathering pipelines is expected to be completed in 2016. As of
December 31, 2015, the Company had invested approximately $20 million in the Processing Plant joint venture, and
approximately $17.5 million in the gathering pipeline joint venture. As of December 31, 2015, the Company has
F-43
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
guaranteed SN Midstream’s remaining commitment to invest approximately $60 million and $17.5 million, respectively,
in the Processing Plant and gathering pipelines joint ventures.
Membership percentage interests in the Processing Plant joint venture and the gathering pipelines joint venture
for the Company and Targa are calculated based on the aggregate capital contributions made by each party related to the
total capital contributions made by both parties. If SN Midstream fails to make capital contributions or the Company
fails to fulfill the guarantee or, in the case of the Processing Plant joint venture, the Company does not elect to contribute
more than $80 million (if the cost to construct the Processing Plant exceeds $160 million) our membership interest in the
joint venture could be reduced. If our membership interest falls below 20%, we have the potential to lose appointed
board seats and voting rights.
Note 15. Subsidiary Guarantors
The Company filed registration statements on Form S-3 with the SEC, which became effective January 14,
2013 and June 11, 2014 and registered, among other securities, debt securities. The subsidiaries of the Company named
therein are co-registrants with the Company, and the registration statement registered guarantees of debt securities by
such subsidiaries. As of December 31, 2015, such subsidiaries are 100 percent owned by the Company and any
guarantees by these subsidiaries will be full and unconditional (except for customary release provisions). In the event
that more than one of these subsidiaries provide guarantees of any debt securities issued by the Company, such
guarantees will constitute joint and several obligations.
The Company also filed a registration statement on Form S-4 with the SEC, which became effective on June 20,
2014, pursuant to which the Company completed an offering of the 7.75% Notes, which are guaranteed by its
subsidiaries named therein. As of December 31, 2015, such guarantor subsidiaries are 100 percent owned by the
Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions)
and are joint and several and any non-guarantor subsidiaries of the Company are “minor” within the meaning of Rule 3-
10 of Regulation S-X.
The Company also filed a registration statement on Form S-4 with the SEC, which became effective on January
23, 2015, pursuant to which the Company completed an offering of the 6.125% Notes, which are guaranteed by its
subsidiaries named therein. As of December 31, 2015, such guarantor subsidiaries are 100 percent owned by the
Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions)
and are joint and several and any non-guarantor subsidiaries of the Company are “minor” within the meaning of Rule 3-
10 of Regulation S-X.
The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions
upon the ability of its subsidiaries to distribute funds to the Company.
Note 16. Investments
On October 2, 2015, the Company, via SN Midstream, entered into joint venture agreements with an affiliate of
Targa to, among other things, construct the Processing Plant and associated high pressure gathering pipelines near the
Company’s Catarina asset in the Eagle Ford Shale. The Processing Plant, which will be located in La Salle County,
Texas, is expected to have initial capacity of 200 MMcf per day with the ability to increase to 260 MMcf per day. In
connection with the Processing Plant joint venture agreement, the SN Midstream has committed to invest approximately
$80 million and receive a 50% ownership interest in the joint venture owning the Processing Plant. Construction is
expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, the SN Midstream
F-44
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
has committed to invest approximately $35 million and receive a 50% ownership interest in the joint venture owning the
gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant.
Construction on the gathering pipelines is expected to be completed in 2016. The Company is accounting for these joint
ventures as equity method investments as Targa is the operator of the joint ventures and has the most influence with
respect to the normal day-to-day construction and operating decisions. As of December 31, 2015, the Company had
invested approximately $20 million in the Processing Plant joint venture, and approximately $17.5 million in the
gathering pipeline joint venture. We have included these equity method investment balances in the “Other Assets” long-
term asset line on the balance sheet. There were no earnings or losses from the Processing Plant joint venture or the
gathering pipelines joint venture for the period ended December 31, 2015.
On October 2, 2015, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided
interest in the Silver Oak II Gas Processing Facility (the “SOII Facility”) in Bee County, Texas for a purchase price of
$12.5 million. Targa owns the remaining undivided 90% interest in the SOII Facility, which is operated by Targa.
Concurrently with the execution of the purchase and sale agreement for the SOII Facility, the Company entered into a
firm gas processing agreement, whereby Targa will process a firm quantity, 125,000 Mcf/d, from the firm
commencement date of March 1, 2016 until the in-service date of the Processing Plant discussed above. The Company is
accounting for the investment in the SOII Facility as an equity method investment as Targa is the operator and majority
interest owner of the SOII Facility. As of December 31, 2015, the Company had invested $12.5 million in the SOII
Facility. Losses from the SOII Facility investment for the period ended December 31, 2015 were immaterial to the
consolidated financial statements.
Note 17. Subsequent Events
On January 22, 2016, the Company, the Guarantors, the Administrative Agent and the other agents and lenders
party thereto entered into the Sixth Amendment.
The Sixth Amendment, among other things, amended the Second Amended and Restated Credit Agreement and
its exhibits and schedules to (a) permit repurchases of senior unsecured notes and equity interests issued by the Company
for aggregate cash consideration not to exceed approximately $98.5 million ($100 million less approximately $1.5
million attributable to equity interests already purchased by an unrestricted subsidiary and distributed to the Company),
subject to a sublimit of approximately $48.5 million for repurchases of equity interests other than preferred stock, subject
to certain limitations; (b) permit the incurrence by the Company of (x) secured second lien debt; provided that: (i) such
debt shall be (A) in an aggregate principal amount not to exceed $400,000,000 plus any principal representing payment
of interest in kind and (B) subject to an approved intercreditor agreement at all times that any obligation under the
Second Amended and Restated Credit Agreement is outstanding; and (ii) such debt shall not (A) provide for any
scheduled payment of principal, scheduled mandatory redemption or scheduled sinking fund payment before the date
that is 180 days following June 30, 2019 or (B) contain terms and conditions, taken as a whole, more restrictive than
those set forth in the Second Amended and Restated Credit Agreement and (y) second lien debt refinancing or replacing
the foregoing debt, to the extent permitted under the intercreditor agreement; (c) reduce the borrowing base from $500
million to $425 million; (d) provide for the reduction of the borrowing base by 25% of the amount of any second lien
debt incurred (other than second lien debt issued in exchange for or the proceeds of which are used to redeem the
Company’s senior unsecured notes and other than second lien debt that refinances second lien debt or represents
payment of interest in kind); (e) provide that the maximum amount of senior unsecured notes issued by the Company
that may be outstanding at any time, after giving effect to such issuance and any repayment of senior unsecured notes out
of the proceeds thereof and the proceeds of any permitted second lien debt issued substantially contemporaneously
therewith, is not greater than $2,150,000,000 minus the aggregate principal amount of second lien debt (excluding
refinancings and replacements thereof and principal comprised of payments of interest in kind); (f) reflect the formation
F-45
Sanchez Energy Corporation
Notes to the Consolidated Financial Statements (Continued)
and designation of two additional unrestricted subsidiaries; (g) permit the Loan Parties to make investments in
unrestricted subsidiaries in the form of equity interests of other unrestricted subsidiaries; (h) eliminate the ability of
unrestricted subsidiaries to purchase debt and equity interests issued by the Company; and (i) provide for other technical
amendments, clarifications and corrections.
F-46
Sanchez Energy Corporation
Supplementary Quarterly Financial Results (Unaudited)
The following table presents the Company’s unaudited quarterly financial information for 2015 and 2014 (in
thousands, except per share amounts):
2015:
Oil and natural gas revenue
Impairment of oil and natural gas properties
Operating costs and expenses
Operating income (loss)
Interest and other income (expense)
Interest expense
Net gains (losses) on commodity derivatives
Other income (expense), net
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Less:
Preferred stock dividends
Net income allocable to participating securities (1) (2)
Net income (loss) attributable to common
stockholders
Basic income (loss) per share (3)
Weighted average common shares outstanding - basic
Diluted income (loss) per share (3)
Weighted average common shares outstanding - diluted
First
Third
Fourth
Quarter Quarter
Second
Quarter Quarter
$ 110,593 $
(441,450)
(166,967)
(497,824)
(1,824)
(31,558)
41,303
7,921
(489,903)
7,442
(497,345)
141,128 $ 114,526 $ 109,532
—
(454,628)
(468,922)
(116,122)
(148,401)
(170,640)
(6,590)
(488,503)
(498,434)
(359)
(753)
773
(31,899)
(31,442)
(31,500)
61,336
103,996
(33,749)
29,078
71,801
(64,476)
22,488
(416,702)
(562,910)
—
158
—
22,488
(416,860)
(562,910)
(3,991)
—
(3,991)
—
(3,991)
—
$ (501,336) $ (566,901) $ (420,851) $
$
(8.83) $
(9.91) $
(7.33)
56,805
57,184
57,426
$
(8.83) $
(9.91) $
(7.33) $
56,805
57,184
57,426
(4,035)
—
18,453
0.32
57,490
0.32
57,490
F-47
2014:
Oil and natural gas revenue
Impairment of oil and natural gas properties
Operating costs and expenses
Operating income
Interest and other income
Interest expense
Net gains (losses) on commodity derivatives
Other income (expense), net
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Less:
Preferred stock dividends
Net income allocable to participating securities (1) (2)
Net income (loss) attributable to common
stockholders
Basic income (loss) per share (3)
Weighted average common shares outstanding - basic
Diluted income (loss) per share (3)
Weighted average common shares outstanding - diluted
First
Second
Third
Fourth
Quarter Quarter Quarter Quarter
$ 134,562 $ 151,661 $ 207,350 $ 172,491
(213,821)
(153,497)
(194,827)
192
(31,655)
130,806
99,343
(95,484)
(33,375)
(62,109)
—
(106,875)
27,687
12
(13,272)
(9,117)
(22,377)
5,310
1,865
3,445
—
(151,580)
55,770
82
(27,612)
47,416
19,886
75,656
26,625
49,031
—
(121,205)
30,456
3
(17,261)
(31,900)
(49,158)
(18,702)
(6,544)
(12,158)
(18,193)
—
(7,132)
—
(4,274)
(2,068)
(3,991)
—
$ (14,748) $ (19,290) $
(0.38) $
$
(0.31) $
47,025
50,602
$
(0.31) $
(0.38) $
47,025
50,602
0.77
55,732
42,689 $ (66,100)
(1.18)
55,855
(1.18)
55,855
0.69 $
68,340
(1) No losses are allocated to participating restricted stock. Such securities do not have a contractual obligation to share
in the Company’s losses.
(2) The sum of quarterly net income allocable to participating securities will not agree with total year net income
allocable to participating securities as each quarterly computation is based on the allocation of net income for the
quarter to the participating securities.
(3) The sum of quarterly net income per share may not agree with total year net income per share as each quarterly
computation is based on the allocation of net income for the quarter to the participating securities and the weighted
average shares outstanding.
F-48
Sanchez Energy Corporation
Supplemental Information on Oil and Natural Gas Exploration,
Development and Production Activities
(Unaudited)
The Company’s oil and natural gas properties are located within the United States of America, which
constitutes one cost center.
Capitalized Costs—Capitalized costs and accumulated depreciation, depletion and impairment relating to the
Company’s oil and natural gas producing activities are summarized below as of the dates indicated (in thousands):
2015
As of December 31,
2014
2013
Oil and Natural Gas Properties:
Unproved
Proved
Total Oil and Natural Gas Properties
Less Accumulated depreciation, depletion,
amortization and impairment
$
253,529 $ 385,827 $ 244,570
1,297,961
1,542,531
2,582,441
2,968,268
2,914,867
3,168,396
Net oil and natural gas properties capitalized
$
(2,412,293)
(157,043)
(706,590)
756,103 $ 2,261,678 $ 1,385,488
Costs Incurred—Costs incurred in oil and natural gas property acquisition, exploration and development
activities are summarized below (in thousands):
Exploration costs
Development costs
Acquisition and Divestiture costs:
Proved properties
Unproved properties
Total Costs Incurred
Year Ended December 31,
2014
64,534 $
2015
30,523 $
512,208
806,644
2013
22,453
492,232
$
—
8,508
411,816
432,271
244,570
122,224
551,239 $ 1,425,673 $ 1,171,071
$
Seismic costs included in exploration costs
$
1,446 $
833 $
4,160
Results of Operations—Results of operations for the Company’s oil, NGL and natural gas producing activities
are summarized below (in thousands):
Oil, NGL, and natural gas revenue
Less operating expenses:
Year Ended December 31,
2015
2014
475,779 $ 666,064 $ 314,420
2013
$
Oil, NGL, and natural gas production expenses
Production and ad valorem taxes
Depreciation, depletion, amortization and accretion
Impairment of oil and natural gas properties
(35,669)
(17,334)
(134,845)
—
Results of operations from oil and gas producing activities $ (1,417,191) $ (17,222) $ 126,572
(156,528)
(26,870)
(344,572)
(1,365,000)
(93,581)
(37,787)
(338,097)
(213,821)
Reserves—Proved reserves are those quantities of oil, NGL and natural 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that
F-49
renewal is reasonably certain, regardless of whether deterministic or probalistic methods are used for the estimation. The
project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will
commence the project within a reasonable time.
Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared
with the cost of a new well.
Proved undeveloped reserves (“PUDs”) are reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage
are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled,
unless evidence using reliable technology exists that establishes reasonable certainty of producing economic quantities at
a greater distance. Only those undrilled locations that are scheduled to be drilled within five years pursuant to a
development plan can be allocated to undeveloped reserves, unless the specific circumstances justify a longer time. As of
December 31, 2015, the Company did not have any PUDs previously disclosed that have remained undeveloped for five
years or more and no PUD locations included in the Company’s proved oil reserves are scheduled to be drilled after five
years.
Estimates of proved developed and undeveloped reserves for the periods presented are based on estimates made
by the independent engineers, Ryder Scott.
Proved reserves for all periods presented were estimated in accordance with the guidelines established by the
SEC and FASB. The rules require SEC reporting companies to prepare their reserve estimates based on the average
prices during the 12 month period prior to the ending date of the period covered in the report, determined as the
unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period,
unless prices were defined by contractual arrangements. The product prices used to determine the future gross revenues
for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from
the market. The pricing used for the estimates of the Company’s reserves of oil and condensate as of December 31, 2015,
2014 and 2013 was based on unweighted twelve month average West Texas Intermediate posted prices of $50.28, $94.99
and $96.78, respectively. The pricing used for the estimates of the Company’s reserves of natural gas as of December 31,
2015, 2014 and 2013 were based on an unweighted twelve month average Henry Hub spot natural gas prices average of
$2.58, $4.35 and $3.67, respectively. The pricing used for the estimates of the Company’s reserves of natural gas liquids
as of December 31, 2015, 2014 and 2013 were based on an unweighted twelve month average Mt. Belvieu prices
average of $19.90, $44.84 and $41.23, respectively.
F-50
Net proved quantities summary
The following table sets forth the net proved, proved developed and proved undeveloped reserves activity for
the years ended December 31, 2015, 2014 and 2013:
Balance as of December 31, 2012
Revisions of previous estimates
Extensions and discoveries
Purchases of reserves in place
Production
Balance as of December 31, 2013
Revisions of previous estimates
Extensions and discoveries
Purchases of reserves in place
Production
Balance as of December 31, 2014
Revisions of previous estimates
Extensions and discoveries
Purchases (sales) of reserves in place
Production
Balance as of December 31, 2015
Proved developed reserves:
As of December 31, 2013
As of December 31, 2014
As of December 31, 2015
Proved undeveloped reserves:
As of December 31, 2013
As of December 31, 2014
As of December 31, 2015
Natural
Gas
Liquids
(mbbl)
310
2,286
1,830
2,644
(455)
6,615
3,901
6,612
20,746
(2,590)
35,284
(1,999)
10,091
(824)
(5,754)
36,798
Natural
Gas
(mmcf)
15,788
(5,923)
8,894
24,445
(3,048)
40,156
6,412
32,691
145,222
(14,828)
209,653
3,427
63,860
(4,871)
(37,594)
234,475
mboe (1)
21,207
(309)
17,030
24,671
(3,872)
58,727
6,231
24,168
56,775
(11,141)
134,760
(17,823)
35,103
(5,213)
(19,184)
127,643
Oil (mbo)
18,266
(1,608)
13,719
17,952
(2,909)
45,420
1,261
12,107
11,826
(6,080)
64,534
(16,395)
14,369
(3,578)
(7,165)
51,765
17,973
27,460
21,718
3,309
18,554
20,803
20,582
110,543
132,911
24,712
64,438
64,672
27,447
37,074
30,048
3,306
16,730
15,995
19,574
99,110
101,564
34,015
70,322
62,970
(1) Oil equivalents are determined under the relative energy content method by using the ratio of 6.0 mcf of gas to 1.0
bo of oil.
F-51
Standardized Measure—The standardized measure of discounted future net cash flows relating to the
Company’s ownership interest in proved oil, NGL and natural gas reserves as of December 31, 2015, 2014 and 2013 is
shown below (in thousands):
Standardized Measure
Future cash inflows
Future production costs
Future development costs
Future income taxes
Discount to present value at 10% annual rate
Standardized measure of discounted future net cash flows
2015
As of December 31,
2014
$ 3,424,682 $ 7,835,812 $ 4,873,808
(1,293,653)
(1,744,947)
(900,820)
(635,942)
(547,634)
—
(450,319)
(922,146)
593,474 $ 1,780,578 $ 1,209,555
(2,635,281)
(1,639,991)
(407,193)
(1,372,769)
$
2013
The future cash flows are based on average first-day-of-month prices during the prior 12-month period and cost
rates in existence at the time of the projections.
Changes in standardized measure of discounted future net cash flows—Changes in standardized measure of
discounted future net cash flows relating to proved oil, NGL and natural gas reserves for each of the three years in the
period ended December 31, 2015 are summarized below (in thousands):
Year Ended December 31,
2014
2015
2013
$ 1,780,578 $ 1,209,555 $ 286,300
(725,716)
(53,586)
130,752
(8,073)
448,464
347,503
(535,580)
(261,417)
113,008
(167,250)
629,403
455,182
120,955
28,630
590,559
552,887
—
—
(200,822)
29,379
923,255
571,023
593,474 $ 1,780,578 $ 1,209,555
(1,790,803)
(120,836)
279,679
(292,382)
142,761
437,705
178,058
—
(136,828)
115,542
(1,187,104)
$
Summary of Changes
Balance, beginning of period
Net changes in prices and costs
Revisions of previous quantity estimates
Extensions, discoveries and improved recovery, less related costs
Sales of oil and gas - net of production costs
Net change in income taxes
Changes in development costs
Accretion of discount
Purchases of reserves in place
Sales of reserves in place
Change in production rates, timing, and other
Net change
Balance, end of period
F-52
SaNchEz ENErgY corPoratioN
CorPorate information
Board of direCtors
Antonio R. Sanchez, Jr.
Executive Chairman of the Board
Antonio R. Sanchez, III
Chief Executive Officer
Gilbert A. Garcia #
Managing Partner of
Garcia Hamilton & Associates
Greg Colvin #
Managing Partner, Chief Operating Officer and
Head of Investor Relations of Sankofa Capital
Sean M. Maher #
Senior Portfolio Manager
RCH Energy
Brian Carney #
Attorney
# Member of the Audit committee
senior management
Antonio R. Sanchez, Jr.
Executive Chairman of the Board
Antonio R. Sanchez, III
Chief Executive Officer
Eduardo A. Sanchez
President
Gleeson Van Riet
Senior Vice President and
Chief Financial Officer
Christopher D. Heinson
Senior Vice President and
Chief Operating Officer
Kirsten A. Hink
Senior Vice President and
Chief Accounting Officer
CorPorate address
Sanchez Energy Corporation
1000 Main Street, Suite 3000
Houston, Texas 77002
(713) 783-8000
Telephone:
Fax:
(713) 756-2784
www.sanchezenergycorp.com
exPloration offiCes
1826 North Loop 1604 West
Suite 300
San Antonio, Texas 78248
Telephone:
Fax:
(210) 530-1239
(210) 530-8194
1920 Sandman Street
Laredo, TX 78044
Telephone:
Fax:
(956) 722-8092
(956) 718-1057
transfer agent and registrar
Continental Stock Transfer
& Trust Company
17 Battery Place, 8th Floor
New York, NY 10004
Telephone:
Fax:
(212) 509-4000
(212) 509-5150
indePendent auditors
KPMG LLP,
Houston, TX 77002
legal Counsel
Akin Gump Strauss Hauer & Feld LLP
Houston, Texas 77002
annual meeting
The Company’s Annual meeting of Shareholders will be
help at 9:00 A.M. CT on Tuesday May 24, 2016 at:
1000 Main Street,
Tunnel Level Conference Room
Houston, Texas 77002
Telephone:
(713) 783-8000
form 10-K
Copies of the Company’s Annual Report on Form 10-K
may be obtained, without charge, by writing to our
Corporate Secretary at our Corporate Address or on the
Company’s website at www.sanchezenergycorp.com.
Common stoCK listing
Listed on NYSE as SN
NYSE: SN www.sanchezenergycorp.com