3
PetroQuest Energy, Inc. is an independent energy
company engaged in the exploration, development,
Corporate Profile
acquisition and production of oil
and natural gas reserves in Texas,
the Arkoma Basin, South Louisiana and the shallow
waters of the Gulf of Mexico.
GOM
GOM
5%
5%
Gulf Coast
20%
Gulf Coast
20%
Woodford
50%
Woodford
50%
2014 Projected CAPEX by Area
East Texas
25%
East Texas
25%
Total Revenues
Net Income (Loss)
Production
Natural Gas, MMcf
NGL, MMcfe
Crude Oil, MBbl
Total, MMcfe
2009
Annual
2010
Annual
2011
Annual
2012
Annual
Q1
Q2
Q3
Q4
2013
Annual
2013
28,065
2,533
600
34,199
24,502
2,470
663
30,951
24,463
2,288
572
30,183
27,466
3,367
521
33,957
6,437
1,065
126
8,256
6,732
1,257
116
8,351
1,239
219
7,706
1,194
220
29,226
4,754
681
8,683
10,906
10,221
38,066
Financial ($ Thousands, except per share amounts)
$ 218,684 $ 179,263 $ 160,700 $
141,591 $
36,009 $
38,102 $
55,587 $
53,172 $ 182,870
Preferred Stock Dividends
5,140
5,139
5,139
5,139
(90,190)
47,126
10,548
(132,079)
3,887
1,280
4,949
1,287
1,670
1,287
3,576
1,285
14,082
5,139
Net Income (Loss) Available to
Common Stockholders
$
(95,330) $
41,987 $
5,409 $ (137,218) $
2,607 $
3,662 $
383 $
2,291 $
8,943
Per Common Share:
Basic
Diluted
$
$
(1.72) $
0.67 $
0.08 $
(2.20) $
0.04 $
0.06 $
0.01 $
0.04 $
(1.72) $
0.66 $
0.08 $
(2.20) $
0.04 $
0.06 $
0.01 $
0.04 $
0.14
0.14
Financial & Operational Highlights
Five Year Review
Reserves ($ Thousands, except per unit amounts)
Natural Gas, MMcf
NGL, MMcfe
Crude Oil, MBbl
Total, MMcfe
Percent Developed
Percent Dry Gas
Percent Gulf Coast
Future Undiscounted Net Cash Flows, $000s
SEC PV-10, Before Taxes, $000s
Commodity Prices
PetroQuest Realized, Natural Gas, $/Mcf
Henry Hub Cash Market Average, Natural Gas, $/Mcf
PetroQuest Realized, NGL, $/Mcfe
PetroQuest Realized, Crude Oil, $/Bbl
WTI (Cushing) Spot Average, Crude Oil, $/Bbl
PetroQuest Realized, Natural Gas Equivalent, $/Mcfe
Per Unit Analysis, $/Mcfe
Total Revenues
Lease Operating Expense and Production Taxes
Gas Gathering Costs
Gross Operating Margin
Interest Expense
General and Administrative
Preferred Stock Dividends
Gross Cash Margin
2009
2010
2011
2012
2013
156,853
10,508
1,931
178,947
174,566
241,926
192,968
8,373
1,623
15,111
1,395
25,360
1,655
192,677
265,407
228,258
62%
65%
88%
23%
91%
13%
61%
91%
9%
74%
85%
13%
254,168
29,140
3,084
301,811
67%
84%
19%
272,271
$ 442,505
$ 635,327
$ 406,818
176,995
$
255,651
$
341,373
$ 239,269
$
$
769,968
474,818
$
$
5.84
3.94
5.38
68.57
61.99
6.39
6.40
1.26
0.01
5.13
0.37
0.55
0.15
4.37
4.37
7.78
79.47
79.51
5.78
5.79
1.42
0.00
4.37
0.32
0.69
0.17
3.19
$
$
$
3.22
4.00
9.51
104.99
95.04
5.32
5.32
1.38
0.00
3.94
0.32
0.68
0.17
2.77
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2.31
2.75
6.32
108.97
94.10
4.17
4.17
1.17
0.00
3.00
0.29
0.68
0.15
1.88
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2.99
3.73
5.23
103.49
98.05
4.80
4.80
1.25
0.00
3.55
0.57
0.70
0.14
2.14
$
4.06
$
$
$
$
$
PetroQuest Energy – Focused On Resources,
Returns, And Growth
As investors and regular readers of PetroQuest’s annual report know, I am always an optimist. I believe in the resilience
of our national economy and the recovery in commodity prices that should accompany improving macro-economic
conditions. I think 2013 was a pivotal year for overall economic conditions as well as commodity prices in the
United States; although it may be a modest macro-economic recovery, I do think an economic recovery is underway.
To Our Stockholders
The shale revolution has demonstrated how abundant our natural gas resources are in this country.
I am a proponent of utilizing natural gas as both a bridge fuel in our nation, as well as an exported commodity.
I am not convinced we will export gas on sufficient a scale to fully expose domestic gas prices to international
market pricing, but I certainly believe exportation can be used to moderate the volatility of domestic natural
gas prices. Regarding the use of natural gas as a bridge fuel, over the past few years our industry has touted the
resource volumes discovered in various U.S. shale gas plays, and although the wheels of change are often fairly
slow to rotate in the United States, I think the trend of commercial fleet conversions to natural
gas as a transportation fuel will continue. As this happens, I expect that there will eventually be
infrastructure constructed to support the long-haul over-the-road transportation fleets on our
interstate highway network. This development will be the strategic signal that large-scale use
of natural gas in the transportation sector is underway.
Proved Reserves, MMcfe
There has been a lot of attention in our industry, within both the political establishment and
media, regarding the potential to export natural gas. Several facilities along the U.S. Gulf Coast
and elsewhere are nearing completion, which should allow some level of export gas throughput.
Obviously this is a positive step for producer companies like PetroQuest, and any daily export
volumes should positively impact gas prices from the demand side. Given that gas prices in Europe
and the far East range between two and eight times higher than domestic prices, it only makes good
business sense that we should be able to export a small portion of our resources to capture some of
this arbitrage opportunity. Job creation to manufacture and maintain full-scale liquefaction facilities
throughout the United States would be a benefit on a national level, and depending on how much
gas ultimately is exported, the national benefit might extend into the geopolitical arena. Recent
events in the Ukraine, along with historical Eastern European reliance on Russia for gas imports,
may ultimately result in a global gas market served by a variety of LNG exporters. Exporting LNG from
the U.S. could potentially benefit not only the U.S. economy, but enable the U.S. to compete globally
in a variety of markets as nations like Poland and the Ukraine seek diversified energy supplies.
Together, there are a number of macro-economic and industry-specific developments that should
positively impact natural gas prices over the next few years. 2013 was a better year than 2012 in
terms of average natural gas prices, and as a result of the extreme winter we have just witnessed,
2014 should be better than last year. I have not discussed oil price fundamentals because I think
over the next few years the oil markets should remain fairly stable. Yes, there will be short-term
seasonal price fluctuations and the occasional geopolitical event may impact oil prices, but in
general the increasing productivity of oil prone basins in the U.S. continues to add to overall
U.S. oil production. At PetroQuest we remain focused on finding and developing oil or natural
gas liquids-rich projects to generate cash flow, but I still think there is higher upside potential for
natural gas price moves than oil. This is why I think it is so important to consider macro-economic
factors when considering an investment in PetroQuest given our estimated 2014 production split
is approximately 70% natural gas and 30% oil and natural gas liquids.
2009
2010
2011
2012
2013
PPV-10, Before Taxes, $000
2009
2010
2011
2012
2013
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
3
We have laid the foundation
for 2014 to be a year of
production and reserve
growth in excess of 20%.
Deep Resources
2013 was an important year for PetroQuest as we made the largest acquisition in the history of
our company. We achieved company records for annual production as well as proved reserves.
Combined with our active leasing campaign, we have laid the foundation for 2014 to be a year of
production and reserve growth in excess of 20% as we fully expect to break the record achieved
in 2013. We plan to drill 80% more gross wells in 2014, which is a continuation of our overall
operational theme of the past few years. With deep resources in our asset portfolio, our focus for 2014
turns to efficient execution of our operations and higher-return projects.
Investors and regular readers of this letter are familiar with the overall PetroQuest strategy of the
past ten years, namely to build, expand and develop long-life onshore resources plays with cash flow
generated from our expertise in finding, developing and operating Gulf Coast assets. These two asset
classes are complimentary in that the free cash flow derived from large, high-return Gulf Coast projects
can be redeployed into our Woodford, Cotton Valley and emerging Mississippian Lime positions.
The overall objective of this growth strategy is to increase production and reserve growth each year
with minimal reinvestment capital expenditures in order to generate the cash flow required to drill
and develop our onshore resource projects. It’s true that our acquisition in 2013 was achieved through
a bond issuance, but the important thing for shareholders to bear in mind when evaluating PetroQuest
is that we are committed to growing production and reserves on debt adjusted per share basis.
Gulf Coast Experience, Gulf Coast Expertise,
Gulf Coast Cash Flow
One of my observations in my 30+ years of energy sector experience is the disparity between
company operating strategies and the ever-shifting asset favorites among energy investors.
This is a natural phenomenon, particularly over the past eight years with the discoveries of various
onshore shale basins, but we have deliberately maintained our focus and expertise in Gulf
Coast assets as a means to generate cash flow for other projects, rather than chasing the latest
“hot” trends and paying exorbitant leasehold rates. This strategy works. In 2012 Gulf Coast
assets generated approximately $50 million in cash flow while requiring less than $20 million in
capital expenditures, and in 2013 they generated nearly $80 million in cash flow while spending
approximately $40 million. In 2014, we project our free cash flow growth trend will continue while
spending only approximately $30 million; in fact, we are allocating only 5% of our capital budget to
the offshore Gulf of Mexico in 2014, while 20% will be allocated to onshore Gulf Coast projects.
That is a perfect demonstration of the value we create by operating in the Gulf Coast because when
Gulf Coast wells are successful they can generate large production and reserve volumes, which in turn
create very large cash flow numbers even in lower commodity price environments. Very simply,
this is why we continue to prioritize Gulf Coast assets as critical elements of the PetroQuest asset mix.
To support this strategy, last year PetroQuest spent approximately $190 million to acquire shallow
offshore proved reserves of 5.3 million barrels of oil equivalent (BOE), which represents a price of
$45,000 per flowing BOE and finding and development costs of $36.41 per BOE. Even more notable
is the fact the transaction included an additional 3.2 million BOE of possible reserves (P3). These assets
generated $28.3 million in free cash flow in the second half of 2013 and are projected to generate
additional substantial free cash flow during 2014. PetroQuest will operate 80% of these reserves,
and will re-deploy the cash flow into our long-lived assets to grow production and reserves onshore.
Further, we remain both committed to and excited by our La Cantera/Thunder Bayou projects, which are
located in Vermilion Parish, Louisiana. We believe the La Cantera discovery alone could ultimately produce
over 180 billion cubic feet equivalent (Bcfe) of natural gas, within a deep geologic expression containing
several shallow fields that have produced from 529 Bcfe to over 1.4 trillion cubic feet equivalent (Tcfe).
4
Our Woodford shale
program has proven to
be the crown jewel in
our onshore portfolio.
During 2013, the three wells producing at La Cantera contributed more than $28.1 million in net field level
cash flow. The La Cantera/Thunder Bayou complex is a series of very large fields that contain multi-pay
zones that we are only now beginning to fully understand. La Cantera contains booked volumes of 103
billion cubic feet (Bcf) of proved reserves and we estimate Thunder Bayou contains un-risked reserves
potential of 162 Bcfe. We expect to spud Thunder Bayou during the second quarter of 2014 and if
successful, this project should contribute significant levels of free cash flow over the next several years.
Onshore Resource Plays - Accelerate Development,
Focus On Returns
Now that I have outlined our strategy in terms of generating cash flow from our Gulf Coast assets,
how are we going to deploy that capital to grow the company? The answer lies in our continuing
efforts to acquire, drill and develop onshore resource plays. For many years PetroQuest has
been focused in the Arkoma Woodford shale basin in southeastern Oklahoma. We initially leased
acreage and began drilling in this area in 2004 as part of our diversification effort, which continues,
to create a company with a production and reserves split between high-impact shallow gulf projects
and long-lived onshore resource plays that generate steady production and reserve growth over
time. Our Woodford shale program has proven to be the crown jewel in our onshore portfolio.
One of the critical aspects to leading an energy company is creating an environment in which the
team can generate prospects, pursue ideas, and execute our programs by following the strategic
vision of asset diversity set by the company’s Board and executives. Our initial leasing and drilling
campaign in the Woodford focused on dry gas projects in our Lake McAlester and Hoss Areas,
but when gas prices began to fall a few years ago, our team was tasked with sourcing natural gas
liquids projects. Our team did a magnificent job in creating new liquids-rich drilling opportunities
for PetroQuest in our West Relay and North Relay areas, located in Hughes County, Oklahoma.
We began leasing acreage there four years ago and have continued to add to our position since,
which now comprises over 30,000 acres. These are the areas in which we will focus our 2014
Woodford drilling program, as we plan to drill between 30-50 liquids-rich wells using multi-pad
drilling sites, funding this program through the combination of Gulf Coast-generated cash flow and
approximately $50 million of remaining funds in our Woodford joint venture.
In 2013 we allocated 29% of our capital spending to our Woodford program, and in 2014 we
are going to increase that to 50%, which is in recognition of the superior rates of return we are
generating in addition to our intention to dramatically increase our pace of operations in this
area. Last year I wrote about our continuing evaluation of our Woodford position in order to high-
grade our drilling prospects, prioritizing liquids-rich prospects. This work has been completed
and PetroQuest is in a position to drill over three times as many Woodford wells in 2014 as we did
during 2013. This should result in very significant production growth and reserve additions in our
Woodford acreage. In the last nine years we have drilled 127 Woodford wells; in 2014-15 alone we
expect replicate nearly 80% of this activity as we plan to drill a total of 100 wells.
Along with our Woodford program, we continued to move our East Texas Cotton Valley play forward
in 2013. Rates of return on our liquids-rich Cotton Valley acreage range between 40% at a $3.50 per
MMcfe gas price, to 66% at $4.50 per MMCfe. Our operational efficiency has improved, with average
initial production rates 44% higher in 2013 than 2011; in 2013, PetroQuest Cotton Valley well averaged
6.3 MMcf of gas and 458 BOE of natural gas liquids, per well. This is an area that we continue to
evaluate because of its competitive economics at current gas prices as well as PetroQuest’s running
room in terms of our drilling inventory. As I write this letter, PetroQuest has some 210 gross Cotton
Valley horizontal locations, 188 Bossier horizontal locations and 197 Travis Peak vertical locations with
over 500 additional prospective Upper and Middle Cotton Valley horizontal wells. This is an area
in which our operations team will be drilling wells for years to come. We plan to allocate 25% of our
capital spending to East Texas in 2014 to drill 6 horizontal wells.
5
Finally, we continued to collect seismic and scientific data on
our Mississippian Lime acreage in Northern Oklahoma in 2013.
We are in the process of developing and assessing our reservoir
models to identify our best drilling prospects, and I expect this
effort to continue for the balance of 2014 as our technical teams
further refine our understanding of this play. We do know that
the Mississippian Lime is highly variable, but we are encouraged
that our initial results are in line with other industry well
performance in terms of initial production rates. This area will
remain a focus area for PetroQuest in 2014, but we do not plan to
allocate a great deal of capital or drill many wells in 2014 given the
high-impact projects we have ahead of us in the Gulf Coast/Gulf
of Mexico, Woodford Shale and Cotton Valley.
Farewell To A Good Friend
Let me end this year’s President’s letter by recognizing one of
the long-term visionaries who contributed mightily to the success
of PetroQuest Energy, Dan Fournerat. Dan played a pivotal
role in the success of PetroQuest Energy throughout his 28 year
association with the Company. While he formally joined the
company in 2001, he served as a trusted legal advisor since the
Company’s formation. We were blessed when Dan agreed to join
the company as our General Counsel and Chief Administrative
Officer, a position he held until his untimely passing in September
2013. Dan was a devoted family man and a respected leader
in our community, and he will be sorely missed.
PetroQuest Employees –
Our Number One Resource
As we draw a line under 2013 with this annual report and look
forward to a successful 2014, I want to compliment PetroQuest’s
employees and contractors from the executive level, to our
technical staff, our field operations team, finance/accounting
employees, and the administrative staff, as each and every one
of our 127 employees plays a critical role to our organization and
its success. In the end, investors will evaluate PetroQuest on its
returns and financial performance, but in leading the company,
I know there is much more to our story than just financial and
operational metrics. But I also know there is so much more to our
story in terms of our employees who tirelessly work on behalf
of our investors to produce results. Each and every member
of our team should be proud of their performance in 2013,
and I have great confidence and enthusiasm about a positive
future for PetroQuest Energy in 2014 and beyond.
Charles T. Goodson
President, Chairman, and Chief Executive Officer
February 28, 2014
6
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2013
or
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
Commission File Number: 001-32681
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
State of incorporation:
72-1440714
I.R.S. Employer Identification No.
400 E. Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (337) 232-7028
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $.001 per share
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12 (g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes
No
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days.
Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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 is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes
No
The aggregate market value of the voting common equity held by non-affiliates of the registrant as of June 28, 2013, based on the $3.96 per share closing
price for the registrant's Common Stock, par value $.001 per share, as quoted on the New York Stock Exchange, was approximately $162,000,000 (for purposes
of this disclosure, the registrant assumed its directors, executive officers and beneficial owners of 5% or more of the registrant’s Common Stock were affiliates).
As of February 27, 2014, the registrant had outstanding 65,794,156 shares of Common Stock, par value $.001 per share.
Document incorporated by reference: portions of the definitive Proxy Statement of PetroQuest Energy, Inc. to be filed pursuant to Regulation 14A under
the Securities Exchange Act of 1934 with respect to the Annual Meeting of Stockholders to be held on May 21, 2014, which are incorporated by reference into
Part III of this Form 10-K.
Table of Contents
Page No.
Items 1 and 2 Business and Properties
PART I
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
PART II
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
PART III
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Item 15. Exhibits, Financial Statement Schedules
PART IV
Index to Financial Statements
2
4
19
31
31
31
32
34
34
43
44
44
44
46
46
46
46
46
46
47
56
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this "Form 10-K") contains “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of
1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by
reference into this Form 10-K are forward looking statements. These forward-looking statements are subject to certain risks, trends
and uncertainties that could cause actual results to differ materially from those projected.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Among those risks, trends and uncertainties are:
the volatility of oil and natural gas prices;
our indebtedness and the significant amount of cash required to service our indebtedness;
the recent financial crisis and continuing uncertain economic conditions in the United States and globally;
our ability to obtain adequate financing when the need arises to execute our long-term strategy and to fund our planned
capital expenditures;
limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions
imposed by restrictive debt covenants;
our ability to find, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;
approximately 40% of our production being exposed to the additional risk of severe weather, including hurricanes and
tropical storms, as well as flooding, coastal erosion and sea level rise;
losses and liabilities from uninsured or underinsured drilling and operating activities;
our ability to market our oil and natural gas production;
changes in laws and governmental regulations, increases in insurance costs or decreases in insurance availability, and
delays in our offshore exploration and drilling activities that may result from the April 22, 2010 sinking of the Deepwater
Horizon and subsequent oil spill in the Gulf of Mexico;
our need to obtain bonds or other surety to maintain compliance with regulations as well as regulatory initiatives relating
to oil and natural gas development, hydraulic fracturing, and derivatives;
proposed changes to U.S. tax laws;
competition from larger oil and natural gas companies;
Securities and Exchange Commission (sometimes referred to herein as the "SEC") rules that could limit our ability to
book proved undeveloped reserves in the future;
the likelihood that our actual production, revenues and expenditures related to our reserves will differ from our estimates
of proved reserves;
our ability to identify, execute or efficiently integrate future acquisitions;
ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;
losses or limits on potential gains resulting from hedging production;
the unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel;
the loss of key management or technical personnel;
3
•
•
•
•
•
•
the operating hazards attendant to the oil and gas business;
governmental regulation relating to hydraulic fracturing and environmental compliance costs and environmental
liabilities;
the operation and profitability of non-operated properties;
potential conflicts of interest resulting from ownership of working interests and overriding royalty interests in certain of
our properties by our officers and directors;
the loss of our information and computer systems; and
the impact of terrorist activities on global economies.
Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure
you that such expectations reflected in these forward looking statements will prove to have been correct.
When used in this Form 10-K, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and
similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these
identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially
from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed
under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere
in this Form 10-K.
You should read these statements carefully because they discuss our expectations about our future performance, contain
projections of our future operating results or our future financial condition, or state other “forward-looking” information. You
should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” “Risk Factors” and elsewhere in this Form 10-K could substantially harm our business,
results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common
stock could decline, and you could lose all or part of your investment.
We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we
undertake no obligation to update any of the forward-looking statements in this Form 10-K after the date of this Form 10-K.
As used in this Form 10-K, the words “we,” “our,” “us,” “PetroQuest” and the “Company” refer to PetroQuest Energy,
Inc., its predecessors and subsidiaries, except as otherwise specified. We have provided definitions for some of the oil and natural
gas industry terms used in this Form 10-K in “Glossary of Certain Oil and Natural Gas Terms” beginning on page 52.
Part I
Item 1 and 2. Business and Properties Items
Overview
PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with operations in
Oklahoma, Texas, and the Gulf Coast Basin. We seek to grow our production, proved reserves, cash flow and earnings at low
finding and development costs through a balanced mix of exploration, development and acquisition activities. From the
commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore
properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During
2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower
risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk
profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift
capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our
drilling program across multiple basins.
We have successfully diversified into onshore, longer life basins in Oklahoma and Texas through a combination of
selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in Texas through 2013,
we have invested approximately $1.1 billion into growing our longer life assets. During the ten year period ended December 31,
2013, we have realized a 95% drilling success rate on 918 gross wells drilled. Comparing 2013 metrics with those in 2003, the
year we implemented our diversification strategy, we have grown production by 294% and estimated proved reserves by 262%.
4
At December 31, 2013, 81% of our estimated proved reserves and 63% of our 2013 production were derived from our longer life
assets.
As a result of the impact of low natural gas prices on our revenues and cash flow, we have focused on growing our reserves
and production through a balanced drilling budget with an increased emphasis on growing our oil and natural gas liquids production.
In May 2010, we entered into the Woodford joint development agreement ("JDA"), which provided us with $85 million in cash
during 2010 and 2011, along with a drilling carry that we have utilized since May 2010 to enhance economic returns by reducing
our share of capital expenditures in the Woodford Shale and the Mississippian Lime. During February 2012, we amended the
JDA to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and satisfy the drilling carry ratio. Under
the amended JDA, the Phase 2 drilling carry was expanded to provide for development in both the Mississippian Lime and Woodford
Shale plays whereby we will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2
drilling carry is subject to extensions in one year intervals and as of December 31, 2013, approximately $51.6 million remained
available. See "Liquidity and Capital Resources - Source of Capital: Joint Ventures."
During 2013, we acquired certain producing properties in the shallow waters of the Gulf of Mexico pursuant to the
Purchase and Sale Agreements, each dated as of June 19, 2013, between our subsidiary PetroQuest Energy, L.L.C. and each of
Hall-Houston Exploration II, L.P., Hall-Houston Exploration III, L.P., Hall-Houston Exploration IV, L.P., and GOM-H Exploration,
LLC, respectively ("Gulf of Mexico Acquisition"). The aggregate purchase price of the Gulf of Mexico Acquisition was $188.8
million and it contributed 30.5 Bcfe to our estimated proved reserves at December 31, 2013 as well as 4.5 Bcfe of production
during 2013. Since entering into the JDA and as a result of the Gulf of Mexico Acquisition as well as the success of our drilling
programs in each of our operating areas, we have grown our estimated proved reserves by 69% and production by 11% since year
end 2009, including a 36% increase in our oil and natural gas liquids production during 2013.
Gulf of Mexico Acquisition
On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million,
reflecting an effective date of January 1, 2013. The Gulf of Mexico Acquisition was financed with the net proceeds from the
issuance of an additional $200 million in aggregate principal amount of our 10% Senior Notes due 2017, (sometimes referred to
herein as our "10% senior notes"). The transaction included 16 gross wells located on seven platforms (the "Acquired Assets").
During 2013, the Acquired Assets contributed 4.5 Bcfe of total production, including 235,000 barrels of oil, and added
30.5 Bcfe of estimated proved reserves as of December 31, 2013. As a result of the Gulf of Mexico Acquisition, our acreage
position in the Gulf Coast Basin increased 23% to 46,801 net acres. See "Note 2 - Acquisition" in Item 8. Financial Statements
and Supplementary Data for additional details related to this transaction.
We believe the Gulf of Mexico Acquisition represents both a strategic and transformative transaction for us. This
transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop
our longer-life resource assets. As evidenced by the larger percentage of our production and estimated proved reserves now located
in our longer lived basins, we have successfully leveraged our Gulf Coast free cash flow to help fund our substantial diversification
efforts over the past several years. We plan to utilize a portion of the free cash flow generated from these acquired properties to
accelerate the development of our Woodford Shale and Cotton Valley resource plays. In addition, based upon our experience and
successful track record in exploiting reservoirs in the Gulf Coast Basin and Gulf of Mexico, we believe that we will be able to
create value above the current estimated proved reserves associated with the Acquired Assets.
Business Strategy
Maintain Our Financial Flexibility. Because we operate approximately 89% of our total estimated proved reserves and
manage the drilling and completion activities on an additional 4% of such reserves, we expect to be able to control the timing of
a substantial portion of our capital investments. Our 2014 capital expenditures, which include capitalized interest and overhead
but exclude acquisitions, are expected to range between $140 million and $150 million. We expect to be able to actively manage
our 2014 capital budget in the event commodity prices, or the health of the global financial markets, do not match our expectations.
During 2014, we also plan to maintain our commodity hedging program and, as in during prior years, we may continue to
opportunistically dispose of certain non-core or mature assets to provide capital for higher potential exploration and development
properties that fit our long-term growth strategy. During December 2012, we sold our non-operated Arkansas assets for $8.5
million. During January 2013, we sold 50% of our saltwater disposal systems and related surface assets in the Woodford for net
proceeds of approximately $10 million. During December 2013, we sold our non-operated Wyoming assets for $1.0 million.
Pursue Balanced Growth and Portfolio Mix. We plan to pursue a risk-balanced approach to the growth and stability of
our reserves, production, cash flows and earnings. Our goal is to strike a balance between lower risk development activities and
higher risk and higher impact exploration activities. We plan to allocate our 2014 capital investments in a manner that continues
5
to geographically and operationally diversify our asset base, while focusing on oil and natural gas liquids projects as the pricing
for these products is presently expected to be more attractive than that of natural gas. Through our portfolio diversification efforts,
at December 31, 2013, approximately 81% of our estimated proved reserves were located in longer life and lower risk basins in
Oklahoma and Texas and 19% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. In terms
of production diversification, during 2013, 63% of our production was derived from longer life basins versus 75% and 66% in
2012 and 2011, respectively. Our 2013 production was comprised of 77% natural gas, 11% oil and 12% natural gas liquids.
Target Underexploited Properties with Substantial Opportunity for Upside. We plan to maintain a rigorous prospect
selection process that enables us to leverage our operating and technical experience in our core operating areas. During 2014, we
intend to primarily target properties that provide us with exposure to oil or natural gas liquids reserves and production. In evaluating
these targets, we seek properties that provide sufficient acreage for future exploration and development, as well as properties that
may benefit from the latest exploration, drilling, completion and operating techniques to more economically find, produce and
develop oil and gas reserves. We believe that our deep experience and expertise in operating in the Gulf of Mexico can enhance
the value of the assets we acquired in the Gulf of Mexico Acquisition.
Concentrate in Core Operating Areas and Build Scale. We plan to continue focusing on our operations in Oklahoma,
Texas and the Gulf Coast Basin. Operating in concentrated areas helps us better control our overhead by enabling us to manage
a greater amount of acreage with fewer employees and minimize incremental costs of increased drilling and production. We have
substantial geological and reservoir data, operating experience and partner relationships in these regions. We believe that these
factors, combined with the existing infrastructure and favorable geologic conditions with multiple known oil and gas producing
reservoirs in these regions, will provide us with attractive investment opportunities, as evidenced by the Gulf of Mexico Acquisition.
Manage Our Risk Exposure. We plan to continue several strategies designed to mitigate our operating risks. We have
adjusted the working interest we are willing to hold based on the risk level and cost exposure of each project. For example, we
typically reduce our working interests in higher risk exploration projects while retaining greater working interests in lower risk
development projects. Our partners often agree to pay a disproportionate share of drilling costs relative to their interests, allowing
us to allocate our capital spending to maximize our return and reduce the inherent risk in exploration and development activities.
We also strive to retain operating control of the majority of our properties to control costs and timing of expenditures and we
expect to continue to actively hedge a portion of our future planned production to mitigate the impact of commodity price fluctuations
and achieve more predictable cash flows.
2013 Financial and Operational Summary
During 2013, we invested $328.1 million in exploratory, development and acquisition activities. We drilled 36 gross
exploratory wells and 4 gross development wells realizing an overall success rate of 88%. These activities were financed through
our cash flow from operations, cash on hand, issuance of 10% senior notes and borrowings under our bank credit facility. During
2013, our production increased 12% to 38.1Bcfe as a result of the Gulf of Mexico Acquisition as well as the success of our La
Cantera prospect and our Oklahoma and Texas drilling programs. Partially offsetting these increases were decreases as a result
of the sale of our non-operated Arkansas assets on December 31, 2012 as well as declining dry gas production in our Woodford
Shale area. Our estimated proved reserves at December 31, 2013 increased 32% from 2012 as discussed in greater detail below.
Oil and Gas Reserves
Our estimated proved reserves at December 31, 2013 increased 32% from 2012 totaling 3.1 MMBbls of oil, 29.1 Bcfe
of natural gas liquids (Ngls) and 254.2 Bcf of natural gas, with a pre-tax present value, discounted at 10%, of the estimated future
net revenues based on average prices during 2013 (“PV-10”) of $475 million. The increase in our estimated proved reserves during
2013 was primarily the result of the Gulf of Mexico Acquisition and the effect of the increase in the historical 12-month average
price per Mcf of natural gas used to calculate our estimated proved reserves, along with the success in our drilling programs. At
December 31, 2013, our standardized measure of discounted cash flows, which includes the estimated impact of future income
taxes, totaled $454 million. See the reconciliation of PV-10 to the standardized measure of discounted cash flows below. Our
PV-10 and standardized measure of discounted cash flows utilized prices (adjusted for field differentials) for the years ended
December 31, 2013 and 2012 as follows:
Oil per Bbl
Natural gas per Mcf
Ngl per Mcfe
12/31/2013 12/31/2012
$106.19
$102.81
$3.11
$5.10
$2.20
$6.07
Ryder Scott Company, L.P., a nationally recognized independent petroleum engineering firm, prepared the estimates of
our proved reserves and future net cash flows (and present value thereof) attributable to such proved reserves at December 31,
6
2013. Our internal reservoir engineering staff is managed by an individual with 32 years of industry experience as a reservoir and
production engineer, including eleven years as a reservoir engineering manager with PetroQuest. This individual is responsible
for overseeing the estimates prepared by Ryder Scott.
The following table sets forth certain information about our estimated proved reserves as of December 31, 2013:
Proved Developed
Proved Undeveloped
Total Proved
Oil (MBbls) NGL (Mmcfe)
23,173
5,967
29,140
2,709
375
3,084
Natural Gas
(Mmcf)
163,728
90,440
254,168
Total Mmcfe*
203,152
98,659
301,811
*
Oil conversion to Mcfe at one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.
As of December 31, 2013, our proved undeveloped reserves (“PUD reserves”) totaled 98.7 Bcfe, a 64% increase from
our PUD reserves at December 31, 2012. This increase was due primarily to the effects of a 41% increase in the historical 12-
month average natural gas price per Mcf used in estimating our reserves, which was $3.11 per Mcf as of December 31, 2013 as
compared to $2.20 per Mcf as of December 31, 2012. During 2013, we spent $3.8 million converting 4 Bcfe of PUD reserves at
December 31, 2012 to proved developed reserves at December 31, 2013. PUD reserves added from extensions and discoveries
were primarily the result of successful drilling in our Woodford Shale acreage in Oklahoma. Following is an analysis of the change
in our PUD reserves as of December 31, 2013:
PUD Reserve balance at December 31, 2012
PUD reserves converted to proved developed
PUD reserves added from revisions or extensions and discoveries
PUD reserves removed for 5 year rule
PUD reserves added due to improved gas prices
PUD reserves acquired
PUD reserves sold
PUD reserves revised
PUD Reserve balance at December 31, 2013
MMcfe
59,993
(4,109)
13,452
(4,279)
33,308
308
(146)
132
98,659
Approximately 76% of our PUD reserves at December 31, 2013 were associated with the future development of our
Oklahoma properties. We expect all of our PUD reserves at December 31, 2013 to be developed over the next five years. At
December 31, 2013, we had no PUD reserves that had been booked for longer than five years. Estimated future costs related to
the development of PUD reserves are expected to total $15.8 million in 2014, $50.0 million in 2015, $36.5 million in 2016, $24.5
million in 2017 and $9.6 million thereafter. However, because 92% of our PUD reserves at December 31, 2013 are comprised of
natural gas, the specific timing of the development of PUD reserves over the next five years is highly dependent upon the prevailing
price of natural gas.
The estimated cash flows from our proved reserves at December 31, 2013 were as follows:
Estimated pre-tax future net cash flows (1)
Discounted pre-tax future net cash flows (PV-10) (1)
Total standardized measure of discounted future net cash flows
$
$
635,348
443,789
$
$
134,620
31,029
Proved Developed
(M$)
Proved
Undeveloped
(M$)
Total Proved
(M$)
$
$
$
769,968
474,818
453,882
(1) Estimated pre-tax future net cash flows and discounted pre-tax future net cash flows (PV-10) are non-GAAP measures
because they exclude income tax effects. Management believes these non-GAAP measures are useful to investors as they
are based on prices, costs and discount factors which are consistent from company to company, while the standardized
measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. As a
result, the Company believes that investors can use these non-GAAP measures as a basis for comparison of the relative
size and value of the Company’s reserves to other companies. The Company also understands that securities analysts and
7
rating agencies use these non-GAAP measures in similar ways. The following table reconciles undiscounted and discounted
future net cash flows to standardized measure of discounted cash flows as of December 31, 2013:
Estimated pre-tax future net cash flows
10% annual discount
Discounted pre-tax future net cash flows
Future income taxes discounted at 10%
Standardized Measure of discounted future net cash flows
Total Proved (M$)
$
$
769,968
(295,150)
474,818
(20,936)
453,882
We have not filed any reports with other federal agencies that contain an estimate of total proved net oil and gas reserves.
Core Areas
The following table sets forth estimated proved reserves and annual production from each of our core areas (in Bcfe) for
the years ended December 31, 2013 and 2012.
Oklahoma Woodford
E. Texas
Gulf Coast Basin (1)
Other (2)
2013
2012
Reserves
Production
Reserves
Production
193.8
48.1
57.2
2.7
301.8
17.0
6.0
14.3
0.8
38.1
146.4
46.7
30.0
5.2
228.3
16.3
6.4
8.7
2.6
34.0
(1) On July 3, 2013 we closed the Gulf of Mexico Acquisition which added 30.5 Bcfe of estimated proved reserves and 4.5
Bcfe of production for year end 2013.
(2) On December 31, 2012 we sold our non-operated Arkansas assets which produced 2 Bcfe in 2012.
Oklahoma - Woodford
During 2013, we continued our evaluation of the Woodford Shale as we drilled and participated in 25 gross wells, achieving
a 100% success rate. In total, we invested $36.2 million during 2013 acquiring approximately 13,500 net acres prospective for
liquids rich Woodford Shale gas and drilling and completing wells. In addition, during 2013 we utilized $21.1 million of total
drilling carry under the amended JDA and plan to continue utilizing the drilling carry during 2014. Average daily production from
our Oklahoma properties during 2013 totaled 47 MMcfe per day, a 5% increase from 2012 average daily production. We added
approximately 23 Bcfe of estimated proved reserves from our drilling program during the year. We also experienced positive
revisions to our proved reserves as a result of higher average prices, which along with our drilling success resulted in a 32%
increase in our estimated proved reserves. We have allocated approximately 50% of our 2014 capital budget to operations in the
Woodford Shale as we expect to participate in the drilling of approximately 58 gross wells, all of which will target liquids rich
gas, as well as obtain 3-D seismic data over acreage recently acquired to target liquids rich gas.
East Texas
During 2013, we invested $11.3 million in our East Texas properties where we drilled one gross well, achieving a 100%
success rate, plugged and abandoned several mature wells and acquired approximately 2,000 net acres. Net production from our
East Texas assets averaged 16.3 MMcfe per day during 2013, a 6% decrease from 2012 average daily production and our estimated
proved reserves increased 3% from 2012, primarily as a result of successful drilling in our Carthage field. We have allocated
approximately 25% of our 2014 capital budget to drilling six gross wells as well as various plugging and abandonment operations
at our Carthage field.
Gulf Coast Basin
During 2013, we drilled five gross wells in the Gulf Coast Basin, achieving a 40% success rate. In total, we invested
$232.9 million in this area including $188.8 million for the Gulf of Mexico Acquisition. Production from this area increased 65%
from 2012 totaling 39.1 MMcfe per day in 2013 due to the Gulf of Mexico Acquisition as well as the inception of production from
our third well at our La Cantera prospect. Our estimated proved reserves in this area increased 91% from 2012 primarily as a
result of the 30.5 Bcfe (net of current year production) added through the Gulf of Mexico Acquisition. We have allocated
8
approximately 25% of our 2014 capital budget to various drilling, re-completion and plugging and abandonment projects in the
Gulf Coast Basin.
Markets and Customers
We sell our oil and natural gas production under fixed or floating market contracts. Customers purchase all of our oil and
natural gas production at current market prices. The terms of the arrangements generally require customers to pay us within 30
days after the production month ends. As a result, if the customers were to default on their payment obligations to us, near-term
earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections,
we do not believe that the loss of these customers or any other single customer would adversely affect our ability to market
production. Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:
•
•
•
•
•
•
•
•
the extent of domestic production and imports of oil and natural gas;
the proximity of the natural gas production to pipelines;
the availability of capacity in such pipelines;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and natural gas production; and
federal regulation of gas sold or transported in interstate commerce.
We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can
be obtained for the oil and natural gas we produce.
In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products,
we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on
the Company. During 2013, one customer accounted for 35% and two accounted for 14% each of our oil and natural gas revenue.
During 2012, one customer accounted for 30%, one accounted for 17% and one accounted for 12% of our oil and natural gas
revenue. During 2011, one customer accounted for 20%, one accounted for 18%, one accounted for 15% and one accounted for
11% of our oil and natural gas revenue. These percentages do not consider the effects of commodity hedges. We do not believe
that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the availability
of other purchasers.
9
Production, Pricing and Production Cost Data
The following table sets forth our production, pricing and production cost data during the periods indicated. Three of our
core areas, the Gulf Coast Basin, East Texas and Oklahoma, which includes primarily Woodford Shale reserves, represented greater
than 15% of our total estimated proved reserves.
Production:
Oil (Bbls):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Oil (Bbls)
Gas (Mcf):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Gas (Mcf)
NGL (Mcfe):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total NGL (Mcfe)
Total Production (Mcfe):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Production (Mcfe)
Average sales prices (1):
Oil (per Bbl):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Oil (per Bbl)
Gas (per Mcf)
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Gas (per Mcf)
NGL (per Mcfe)
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total NGL (per Mcfe)
Total Per Mcfe:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Per Mcfe
Year Ended December 31,
2012
2011
2013
512,041
82,500
971
85,468
680,980
9,876,771
4,123,416
15,055,601
170,055
29,225,843
1,312,995
1,333,725
1,971,376
136,127
4,754,223
14,262,012
5,952,141
17,032,803
818,990
38,065,946
346,513
87,368
171
86,538
520,590
5,691,109
4,360,290
15,349,219
2,065,610
27,466,228
885,881
1,479,441
947,935
53,517
3,366,774
8,656,068
6,363,939
16,298,180
2,638,355
33,956,542
$
$
105.74
98.61
90.52
97.59
103.83
$
108.75
104.42
92.53
95.75
105.85
3.70
3.73
2.25
3.54
2.95
7.12
4.70
4.31
5.21
5.22
7.02
5.00
2.49
11.79
4.78
2.92
2.82
1.51
2.20
2.06
8.45
5.72
4.49
6.30
6.10
7.14
4.69
1.69
4.99
3.90
425,145
96,923
145
49,883
572,096
6,342,638
2,871,284
12,736,622
2,512,389
24,462,933
1,356,384
924,668
553
6,241
2,287,846
10,249,892
4,377,490
12,738,045
2,817,928
30,183,355
108.50
101.59
89.61
85.61
105.33
4.12
3.92
2.42
3.12
3.11
10.41
8.19
5.15
9.49
9.51
8.43
6.55
2.42
4.32
5.24
10
Average Production Cost per Mcfe (2):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Average Production Cost per Mcfe
(1) Does not include the effect of hedges.
(2) Production costs do not include production taxes.
Oil and Gas Producing Wells
Year Ended December 31,
2012
2011
2013
$
$
1.60
1.47
0.47
5.03
1.15
$
1.78
1.56
0.49
2.12
1.15
1.61
2.12
0.76
1.08
1.28
The following table details the productive wells in which we owned an interest as of December 31, 2013:
Gross
Net
Productive Wells:
Oil:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Gas:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total
23
4
1
27
55
24
98
584
—
706
761
12.09
3.32
0.03
9.34
24.78
11.80
65.12
166.45
—
243.37
268.15
Of the 761 gross productive wells at December 31, 2013, two had dual completions.
11
Oil and Gas Drilling Activity
The following table sets forth the wells drilled and completed by us during the periods indicated. All wells were drilled
in the continental United States.
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
Exploration:
Productive:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Non-productive:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total
Development:
Productive:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Non-productive:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total
1
1
22
7
31
3
—
—
2
5
36
1
—
3
—
4
—
—
—
—
—
4
0.94
0.99
5.66
2.11
9.70
0.62
—
—
0.62
1.24
10.94
0.24
—
1.36
—
1.60
—
—
—
—
—
1.60
2
6
30
46
84
—
—
1
1
2
86
—
—
15
6
21
—
—
—
—
—
21
0.74
3.25
7.15
4.73
15.87
—
—
0.34
0.50
0.84
16.71
—
—
4.78
0.10
4.88
—
—
—
—
—
4.88
5
4
35
50
94
—
1
—
—
1
95
—
2
1
20
23
—
—
—
—
—
23
2.28
1.34
9.95
4.58
18.15
—
0.50
—
—
0.50
18.65
—
0.60
0.05
0.68
1.33
—
—
—
—
—
1.33
At December 31, 2013, we had 19 gross (14.26 net) wells in progress in Oklahoma, Texas and the Gulf Coast Basin.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of
December 31, 2013:
Kansas
Louisiana
Mississippi
Oklahoma
Texas
Federal Waters
Total
Leasehold Acreage
Developed
Gross
—
4,954
721
102,344
47,224
50,657
205,900
Net
—
1,614
721
48,463
24,865
31,470
107,133
Undeveloped
Gross
Net
4,091
11,653
—
89,039
9,607
7,124
121,514
2,046
6,593
—
58,705
4,658
7,124
79,126
12
Leases covering 17% of our net undeveloped acreage are scheduled to expire in 2014, 19% in 2015, 27% in 2016 and
37% thereafter. Of the acreage subject to leases scheduled to expire during 2014, 65% relates to undeveloped acreage in the
Mississippian Lime trend where we are evaluating future development plans after a full review of seismic data. We expect to hold
the majority of the acreage scheduled to expire in 2014 through drilling or lease extensions.
Title to Properties
We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally
accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially
from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the
following:
•
•
•
•
•
royalties and other burdens and obligations, express or implied, under oil and gas leases;
overriding royalties and other burdens created by us or our predecessors in title;
a variety of contractual obligations (including, in some cases, development obligations) arising under operating
agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their
titles;
back-ins and reversionary interests existing under purchase agreements and leasehold assignments;
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to
unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and
communitization agreements, declarations and orders; and
•
easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account
in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and
obligations affecting our properties are conventional in the industry for properties of the kind that we own.
Federal Regulations
Sales and Transportation of Natural Gas. Historically, the transportation and sales for resale of natural gas in interstate
commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 and the
Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol
Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to
applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since
1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers
on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some
of the FERC's more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation
service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other
natural gas producers, gatherers and marketers with which we compete.
The Outer Continental Shelf Lands Act (the “OCSLA”), which was administered by the Bureau of Ocean Energy
Management, Regulation and Enforcement (the “BOEMRE”) and, after October 1, 2011, its successors, the Bureau of Ocean
Energy Management (the “BOEM”) the Bureau of Safety and Environmental Enforcement (the “BSEE”), and the FERC, requires
that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations
implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction.
Therefore, we do not believe that any FERC, BOEM or BSEE action taken under OCSLA will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.
Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we
sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable
market prices.
Natural gas continues to supply a significant portion of North America's energy needs and we believe the importance of
natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and
demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.
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On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains
many provisions that will encourage oil and gas exploration and development in the U.S. The 2005 EPA directs the FERC, BOEM
and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA
to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as us, to use any deceptive or
manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation
services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC
issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject
to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any
entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material
fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice
that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to
intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the
extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It
therefore reflects a significant expansion of the FERC's enforcement authority. To date, we do not believe we have been, nor do
we anticipate we will be affected any differently than other producers of natural gas.
In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent
orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical
natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural
gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes
of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may
contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions
should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our
administrative costs. To date, we do not believe we have been, nor do we anticipate that we will be affected any differently than
other producers of natural gas.
Sales and Transportation of Crude Oil. Our sales of crude oil, condensate and natural gas liquids are not currently
regulated, and are subject to applicable contract provisions made at market prices. In a number of instances, however, the ability
to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC's
jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on
pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.
The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed
than the FERC's regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate, and natural
gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate
pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based,
although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561,
pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in
the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels
provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline
and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks
significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers.
A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.
Federal Leases. We maintain operations located on federal oil and natural gas leases, which are administered by the
BOEM or the BSEE, pursuant to the OCSLA. The BOEM and the BSEE regulate offshore operations, including engineering and
construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico
shelf, and removal of facilities.
The BOEM handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and
development plans, renewable energy development, NEPA analysis and environmental studies, and the BSEE is responsible for
the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and
environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore
regulatory programs, oil spill response and newly formed training and environmental compliance programs. Our federal oil and
natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require
compliance with detailed regulations and orders that are subject to interpretation and change by the BOEM or BSEE. We are
currently subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal
of all production facilities, structures and pipelines, and the BOEM or the BSEE may in the future amend these regulations. Please
read “Risk Factors” beginning on page 19 for more information on new regulations.
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To cover the various obligations of lessees on the Outer Continental Shelf (the “OCS”), the BOEM and the BSEE generally
require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied.
While we have been exempt from such supplemental bonding requirements in the past, the BOEM has recently notified us that
beginning in 2014 we will need to post supplemental bonding or some form of collateral for certain of our offshore properties.
We are currently evaluating the cost of compliance with these supplemental bonding requirements and the potential collateral that
would be required to be provided. We believe that we will be able to satisfy the collateral requirements using a combination of
our existing cash on hand and letters of credit available under our bank credit facility. Our borrowings available under our bank
credit facility will be reduced to the extent we issue letters of credit to support the issuance of these bonds or other surety. The
cost of compliance with these supplemental bonding requirements is not expected to be material. Under some circumstances, the
BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination
could materially adversely affect our financial condition and results of operations.
Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from
past hurricanes have included structural damage to pipelines, wells, fixed production facilities, semi-submersibles and jack-up
drilling rigs. The BOEM and the BSEE will continue to be concerned about the loss of these facilities and rigs as well as the
potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the
potential for future damage, the BOEMRE historically issued guidance aimed at improving platform survivability by taking into
account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not
more stringent, requirements will be issued by the BOEM or the BSEE for future hurricane seasons. New requirements, if any,
could increase our operating costs to future storms.
The Office of Natural Resources Revenue (the “ONRR”) in the U.S. Department of the Interior administers the collection
of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is
based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR.
Federal, State or American Indian Leases. In the event we conduct operations on federal, state or American Indian oil
and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes,
and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management (“BLM”) or the BOEM or other appropriate federal or state agencies.
The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore
oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such
restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds
a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be cancelled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for
agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous
federal onshore oil and gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the Mineral Act.
State Regulations
Most states regulate the production and sale of oil and natural gas, including:
•
•
•
•
•
requirements for obtaining drilling permits;
the method of developing new fields;
the spacing and operation of wells;
the prevention of waste of oil and gas resources; and
the plugging and abandonment of wells.
The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may
be established on a market demand or conservation basis or both.
We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of
natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in
certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates that we could charge for gas, the transportation of gas, and the construction and
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operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative
authority.
Legislative Proposals
In the past, Congress has been very active in the area of natural gas regulation. New legislative proposals in Congress
and the various state legislatures, if enacted, could significantly affect the petroleum industry. At the present time it is impossible
to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any,
such proposals might have on our operations.
Environmental Regulations
General. Our activities are subject to existing federal, state and local laws and regulations governing environmental
quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials into the
environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect
upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot
predict what effect additional regulation or legislation, enforcement policies, and claims for damages to property, employees, other
persons and the environment resulting from our operations could have on our activities.
Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells and the
operation and construction of pipelines, plants and other facilities for extracting, transporting, processing, treating or storing natural
gas and other petroleum products, are subject to stringent environmental regulation by state and federal authorities, including the
United States Environmental Protection Agency (the “USEPA”). Such regulation can increase the cost of planning, designing,
installing and operating of such facilities. Although we believe that compliance with environmental regulations will not have a
material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and gas production operations, and there
can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such
as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons
resulting from oil and gas production, would result in substantial costs and liabilities to us.
Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and gas
for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or
other solid wastes may have been disposed or released on or under these properties. In addition, many of these properties have
been operated by third parties that controlled the treatment of hydrocarbons or other solid wastes and the manner in which such
substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually
become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including
wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by
prior owners or operators) or to perform remedial plugging operations to prevent future contamination.
We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation
and Recovery Act (“RCRA”) and state statutes. The USEPA has limited the disposal options for certain hazardous wastes.
Furthermore, it is possible that certain wastes generated by our oil and gas operations which are currently exempt from regulation
as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly disposal requirements.
Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials which precipitate on production
equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework,
although such wastes may qualify for the oil and gas hazardous waste exclusion. Primary responsibility for NORM regulation
has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste;
management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted
use. We believe that our operations are in material compliance with all applicable NORM standards.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known
as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with
respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the owner and
operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes
the USEPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to
seek to recover from the responsible persons the costs of such action. State statutes impose similar liability.
Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,”
unless specifically listed or designated and the term does not include natural gas, natural gas liquids, liquefied natural gas, or
synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may
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generate waste that may fall within CERCLA's definition of a “hazardous substance” in the course of our ordinary operations. We
also currently own or lease properties that for many years have been used for the exploration and production of oil and natural
gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the
industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased
by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that
we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under
CERCLA.
Endangered Species Act. Federal and state legislation including, in particular, the federal Endangered Species Act of
1973 (“ESA”), imposes requirements to protect imperiled species from extinction by conserving and protecting threatened and
endangered species and the habitat upon which they depend. With specified exceptions, the ESA prohibits the “taking,” including
killing, harassing or harming, of any listed threatened or endangered species, as well as any degradation or destruction of its habitat.
In addition, the ESA mandates that federal agencies carry out programs for conservation of listed species. Many state laws similarly
protect threatened and endangered species and their habitat. We operate in areas in which listed species may be present. For
example, the American Burying Beetle, listed in 1989 as endangered, is present in regions overlying the Woodford shale in
Oklahoma. As a result, we may be required to adopt protective measures, obtain incidental take permits, and otherwise adjust our
drilling plans to comply with ESA requirements.
Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations
on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States
waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which
an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and
private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses
exist to the liability imposed by the OPA.
The OPA establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs
plus $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose
proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of
credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a
variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas,
type of oil handled, history of discharges and other factors. We carry insurance coverage to meet these obligations, which we
believe is customary for comparable companies in our industry. A failure to comply with OPA's requirements or inadequate
cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.
As a result of the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in 2010, Congress
considered but did not enact legislation that would eliminate the current cap on liability for damages and increase minimum levels
of financial responsibility under OPA. If enacted, such legislation could increase our obligations and potential liability, but adoption
of such legislation is uncertain. We are not aware of the occurrence of any action or event that would subject us to liability under
OPA, and we believe that compliance with OPA's financial responsibility and other operating requirements will not have a material
adverse effect on us.
Discharges. The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the United States, including
wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. Certain facilities that store or
otherwise handle oil are required to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility
Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans
and to obtain and comply with discharge permits. We believe we are in substantial compliance with these requirements and that
any noncompliance would not have a material adverse effect on us. The CWA also prohibits spills of oil and hazardous substances
to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further
provide civil and criminal penalties and liabilities for spills to both surface and groundwaters and require permits that set limits
on discharges to such waters.
Hydraulic Fracturing. Our exploration and production activities may involve the use of hydraulic fracturing techniques
to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact
drinking water, human health and the environment, and in response to a Congressional directive, the USEPA has commissioned
a study to identify potential risks associated with hydraulic fracturing. The USEPA published a progress report on this study in
December 2012 and a final draft report will be delivered in 2014. Additionally, in May 2012 the BLM proposed to regulate the
use of hydraulic fracturing on federal and tribal lands, but following extensive public comment on the proposal, issued a revised
proposal in May 2013. The revised proposal, which also addresses disclosure of fluids used in the hydraulic fracturing process,
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integrity of well construction, and the management and disposal of wastewater that flows back from the drilling process, has also
generated substantial public comment and no final rule has yet been promulgated. Some states now regulate utilization of hydraulic
fracturing and others are in the process of developing, or are considering development of, such rules. Depending on the results of
the USEPA study and other developments related to the impact of hydraulic fracturing, our drilling activities could be subjected
to new or enhanced federal, state and/or local regulatory requirements governing hydraulic fracturing.
Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources
of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved
by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil
and criminal liability for non-compliance. An agency could require us to forego construction or operation of certain air emission
sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit
application were denied, we would have enough permitted or permittable capacity to continue our operations without a material
adverse effect on any particular producing field.
According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly
known as greenhouse gases (“GHG”) may be contributing to global warming of the earth's atmosphere and to global climate
change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions.
The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air
pollutant”, and in response the USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions
under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject
to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing
and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from
all site sources. We are not subject to GHG reporting requirements. In addition, the USEPA promulgated rules that significantly
increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs.
As currently written and based on current Company operations, we are not subject to federal GHG permitting requirements.
Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are
likely to occur. Such developments may affect how these GHG initiatives will impact the Company. Due to the uncertainties
surrounding the regulation of and other risks associated with GHG emissions, the Company cannot predict the financial impact
of related developments on the Company.
The USEPA has promulgated rules to limit air emissions from many hydraulically fractured natural gas wells. The new
regulations will require use of equipment to capture gases that come from the well during the drilling process (so-called green
completions) after January 1, 2015. Other new requirements mandate tighter standards for emissions associated with gas production,
storage and transport. While these new requirements are expected to increase the cost of natural gas production, we do not anticipate
that we will be affected any differently than other producers of natural gas.
Coastal Coordination. There are various federal and state programs that regulate the conservation and development of
coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed to preserve and, where possible, restore the
natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate
land use, water use and coastal development.
The Louisiana Coastal Zone Management Program (“LCZMP”) was established to protect, develop and, where feasible,
restore and enhance coastal resources of the state. Under the LCZMP, coastal use permits are required for certain activities, even
if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water
bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and
production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such
permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas
activities. The LCZMP and its requirement to obtain coastal use permits may result in additional permitting requirements and
associated project schedule constraints.
The Texas Coastal Coordination Act (“CCA”) provides for coordination among local and state authorities to protect
coastal resources through regulating land use, water, and coastal development and establishes the Texas Coastal Management
Program that applies in the nineteen counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review
of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management
Plan. This review may affect agency permitting and may add a further regulatory layer to some of our projects.
OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable
state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the
federal Superfund Amendments and Reauthorization Act, and similar state statutes require us to organize and/or disclose
information about hazardous materials used or produced in our operations. Certain of this information must be provided to
employees, state and local governmental authorities and local citizens.
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Management believes that we are in substantial compliance with current applicable environmental laws and regulations
described above and that continued compliance with existing requirements will not have a material adverse impact on us.
Corporate Offices
Our headquarters are located in Lafayette, Louisiana, in approximately 49,200 square feet of leased space, with exploration
offices in The Woodlands, Texas and Tulsa, Oklahoma, in approximately 13,100 square feet and 11,800 square feet, respectively,
of leased space. We also maintain owned or leased field offices in the areas of the major fields in which we operate properties or
have a significant interest. Replacement of any of our leased offices would not result in material expenditures by us as alternative
locations to our leased space are anticipated to be readily available.
Employees
We had 126 full-time employees as of February 5, 2014. In addition to our full time employees, we utilize the services
of independent contractors to perform certain functions. We believe that our relationships with our employees are satisfactory.
None of our employees are covered by a collective bargaining agreement.
Available Information
We make available free of charge, or through the “Investors—SEC Documents” section of our website at
www.petroquest.com, access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,
and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably
practicable after such material is filed or furnished to the Securities and Exchange Commission. Our Code of Business Conduct
and Ethics, our Corporate Governance Guidelines and the charters of our Audit, Compensation and Nominating and Corporate
Governance Committees are also available through the “Investors—Corporate Governance” section of our website or in print to
any stockholder who requests them.
Item 1A.
Risk Factors
Risks Related to Our Business, Industry and Strategy
Oil and natural gas prices are volatile, and an extended decline in the prices of oil and natural gas would likely have a material
adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.
Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of
our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to
maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon
oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile. For example, for the four years ended
December 31, 2013, the NYMEX-WTI oil price ranged from a high of $113.93 per Bbl to a low of $68.01 per Bbl, while the
NYMEX-Henry Hub natural gas price ranged from a high of $6.01 per MMBtu to a low of $1.91 per MMBtu. These markets will
likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will
depend on numerous factors beyond our control.
These factors include:
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•
relatively minor changes in the supply of or the demand for oil and natural gas;
the condition of the United States and worldwide economies;
• market uncertainty;
•
the level of consumer product demand;
• weather conditions in the United States, such as hurricanes;
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•
•
the actions of the Organization of Petroleum Exporting Countries;
domestic and foreign governmental regulation and taxes, including price controls adopted by the FERC;
political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South
America;
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•
•
the price and level of foreign imports of oil and natural gas; and
the price and availability of alternate fuel sources.
We cannot predict future oil and natural gas prices and such prices may decline. An extended decline in oil and natural
gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations.
Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has
required and may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at
December 31, 2014 to decline compared to our estimated proved reserves at December 31, 2013. Substantially all of our oil and
natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant
to long-term fixed price contracts.
To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected
future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or
natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material
adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.
Our outstanding indebtedness may adversely affect our cash flow and our ability to operate our business, which in turn may
limit our ability to remain in compliance with debt covenants and make payments on our debt.
The aggregate principal amount of our outstanding indebtedness net of cash on hand as of December 31, 2013 was $416
million. We have $75 million of additional availability under our bank credit facility, subject, however, to limitations on incurrence
of indebtedness under the indenture governing our 10% senior notes. In addition, we may also incur additional indebtedness in
the future. Specifically, our high level of debt could have important consequences for you, including the following:
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it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our
10% senior notes, and 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 will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $35 million
per year for interest on our 10% senior notes alone, and to pay quarterly dividends, if declared by our Board of
Directors, on our 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the "Series B Preferred Stock")
of approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital
expenditures, expansion, acquisitions or general corporate or other business activities;
•
the amount of our interest expense may increase because certain of our borrowings in the future may be at variable
rates of interest, which, if interest rates increase, could result in higher interest expense;
• 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, including our 10% senior notes, 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, including our 10% senior notes, 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.
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To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors
beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of
operations.
Our ability to make payments on and to refinance our indebtedness, including our 10% senior notes, and to fund planned
capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a certain extent,
this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond
our control, including the prices that we receive for our oil and natural gas production.
We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will
be available to us under our bank credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness,
including our 10% senior notes, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund
our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital
or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable
terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness
would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable
terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future,
including payments on our 10% senior notes, and any such alternative measures may be unsuccessful or may not permit us to meet
scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations,
liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit,
the European debt crisis and the United States financial market have contributed to increased economic uncertainty and diminished
expectations for the global economy. In addition, future hostilities in the Middle East and the occurrence or threat of terrorist
attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile
prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an
economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global
financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand
for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our
vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and
financial condition.
We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.
Our ability to execute our long-term operating strategy is highly dependent on having access to capital when the need
arises. We historically have addressed our long-term liquidity needs through bank credit facilities, second lien term credit facilities,
issuances of equity and debt securities, sales of assets, joint ventures and cash provided by operating activities. We will examine
the following alternative sources of long-term capital as dictated by current economic conditions:
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borrowings from banks or other lenders;
the sale of non-core assets;
the issuance of debt securities;
the sale of common stock, preferred stock or other equity securities;
joint venture financing; and
production payments.
The availability of these sources of capital when the need arises will depend upon a number of factors, some of which
are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our
credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value and our operating performance.
We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises.
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Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to
changing conditions and engage in other business activities that may be in our best interests.
Our bank credit facility and the indenture governing our 10% senior notes contain a number of significant covenants that,
among other things, restrict or limit our ability to:
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pay dividends or distributions on our capital stock or issue preferred stock;
repurchase, redeem or retire our capital stock or subordinated debt;
• make certain loans and investments;
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place restrictions on the ability of subsidiaries to make distributions;
sell assets, including the capital stock of subsidiaries;
enter into certain transactions with affiliates;
create or assume certain liens on our assets;
enter into sale and leaseback transactions;
• merge or to enter into other business combination transactions;
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enter into transactions that would result in a change of control of us; or
engage in other corporate activities.
Also, our bank credit facility and the indenture governing our 10% senior notes require us to maintain compliance with
specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition
tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition
tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed
capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary
corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations
that the restrictive covenants under our bank credit facility and the indenture governing our 10% senior notes impose on us.
A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition
tests could result in a default under our bank credit facility and our 10% senior notes. A default, if not cured or waived, could result
in all indebtedness outstanding under our bank credit facility and our 10% senior notes to become immediately due and payable.
If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were
then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could
accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.
Our future success depends upon our ability to find, develop, produce and acquire additional oil and natural gas reserves that
are economically recoverable.
As is generally the case in the Gulf Coast Basin where approximately 40% of our current production is located, many of
our producing properties are characterized by a high initial production rate, followed by a steep decline in production. In order to
maintain or increase our reserves, we must constantly locate and develop or acquire new oil and natural gas reserves to replace
those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to
raise the capital necessary to finance our exploration, development and acquisition activities. Without successful exploration,
development or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or
acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would
have a material adverse effect on our financial condition.
Approximately 40% of our production is exposed to the additional risk of severe weather, including hurricanes and tropical
storms, as well as flooding, coastal erosion and sea level rise.
At December 31, 2013, approximately 40% of our production and approximately 20% of our estimated proved reserves
are located in the Gulf of Mexico and along the Gulf Coast Basin. Operations in this area are subject to severe weather, including
hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise. Some of these adverse conditions can be
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severe enough to cause substantial damage to facilities and possibly interrupt production. For example, certain of our Gulf Coast
Basin properties have experienced damages and production downtime as a result of storms including Hurricanes Katrina and Rita,
and more recently Hurricanes Gustav and Ike. In addition, according to certain scientific studies, emissions of carbon dioxide,
methane, nitrous oxide and other gases commonly known as greenhouse gases may be contributing to global warming of the earth's
atmosphere and to global climate change, which may exacerbate the severity of these adverse conditions. As a result, such conditions
may pose increased climate-related risks to our assets and operations.
In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks; however,
losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will
be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will
be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and
results of operations.
Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on
our financial condition and operations.
We maintain several types of insurance to cover our operations, including worker's compensation, maritime employer's
liability and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability
policies. We also maintain operator's extra expense coverage, which covers the control of drilling or producing wells as well as
redrilling expenses and pollution coverage for wells out of control.
We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience
losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully
insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.
Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of
operations.
We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize
the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized
costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated
future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or
fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and
natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended.
This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our
net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month
average of oil and natural gas prices for the prior 12 months. We also assess investments in unproved properties periodically to
determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil
and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience
substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future
development costs increase. As a result of the decline in commodity prices, we recognized ceiling test write-downs totaling $137.1
million and $18.9 million during the years ended December 31, 2012 and December 31, 2011, respectively. While no such write-
downs occurred during 2013, we may experience further ceiling test write-downs or other impairments in the future. In addition,
any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.
Factors beyond our control affect our ability to market oil and natural gas.
The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and
processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing
wells or the delay or discontinuance of development plans for properties. Our ability to market oil and natural gas also depends
on other factors beyond our control. These factors include:
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the level of domestic production and imports of oil and natural gas;
the proximity of natural gas production to natural gas pipelines;
the availability of pipeline capacity;
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the demand for oil and natural gas by utilities and other end users;
the availability of alternate fuel sources;
the effect of inclement weather, such as hurricanes;
state and federal regulation of oil and natural gas marketing; and
federal regulation of natural gas sold or transported in interstate commerce.
If these factors were to change dramatically, our ability to market oil and natural gas or obtain favorable prices for our
oil and natural gas could be adversely affected.
The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010 and the resulting oil spill
may significantly increase our risks, costs and delays.
The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010 and the resulting
oil spill may significantly impact the risks we face. The Deepwater Horizon incident and resulting legislative, regulatory and
enforcement changes, including increased tort liability, could increase our liability if any incidents occur on our offshore operations.
We cannot predict the ultimate impact the Deepwater Horizon incident and resulting changes in regulation of offshore oil and
natural gas operations will have on our business or operations.
In response to the spill, and during a moratorium on deepwater (below 500 feet) drilling activities implemented between
May 30, 2010 and October 12, 2010, the BOEMRE issued a series of active “Notices to Lessees and Operators”, or NTLs, and
adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future.
Offshore operators, including those operating in deepwater, OCS waters and shallow waters, where we have substantial
operations, must comply with strict new safety and operating requirements. For example, permit applications for drilling projects
must meet new standards with respect to well design, casing and cementing, blowout preventers, safety certification, emergency
response, and worker training. Operators of all offshore waters are also required to demonstrate the availability of adequate spill
response and blowout containment resources. In addition, the BSEE imposed, for the first time, requirements that offshore operators
maintain comprehensive safety and environmental programs. Such developments have the potential to increase our costs of doing
business.
We may need to obtain bonds or other surety in order to maintain compliance with applicable regulations, which, if required,
could be costly and reduce borrowings available under our bank credit facility or any other credit facilities we may enter into
in the future.
Regulations with respect to offshore operations govern, among other things, engineering and construction specifications
for production facilities, safety procedures, plugging and abandonment of wells on the OCS of the Gulf of Mexico and removal
of facilities. Lessees subject to these regulations are generally required to have substantial net worth or post bonds or other
acceptable assurances so that the various obligations of lessees on the Gulf of Mexico shelf will be met. While we have been
exempt from such supplemental bonding requirements in the past, the BOEM has recently notified us that beginning in 2014 we
will need to post supplemental bonding or some form of collateral for certain of our offshore properties. We are currently evaluating
the cost of compliance with these supplemental bonding requirements and the potential collateral that would need to be provided.
We believe that we will be able to satisfy the collateral requirements using a combination of our existing cash on hand and letters
of credit available under our bank credit facility. Our borrowings available under our bank credit facility will be reduced to the
extent we issue letters of credit to support the issuance of these bonds or other surety. The cost of compliance with these supplemental
bonding requirements is not expected to be material.
Federal and state legislation and regulatory initiatives relating to oil and natural gas development and hydraulic fracturing
could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to enhance
oil and natural gas production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the
federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique's environmental
effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if
implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the USEPA is
conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The USEPA
published a progress report on this study in December 2012, and the final draft report is scheduled for completion during 2014.
The USEPA has also promulgated rules to limit air emissions from many hydraulically fractured natural gas wells. The new
regulations will require use of equipment to capture gases that come from the well during the drilling process (so-called green
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completions) after January 1, 2015. Other new requirements mandate tighter standards for emissions associated with gas production,
storage and transport. Additionally, in May 2012, the BLM proposed rules to regulate the use of hydraulic fracturing on federal
and tribal lands, but following extensive public comment on the proposals, issued a revised proposal in May 2013. The revised
proposal which also addresses disclosure of fluids used in the fracturing process, integrity of well construction, and the management
and disposal of wastewater that flows back from the drilling process, has also generated substantial public comment and no final
rule has yet been promulgated.
A number of states, including Louisiana and Texas, have required operators or service companies to disclose chemical
components in fluids used for hydraulic fracturing. Some states have also imposed, or are considering, more stringent regulation
of oil and natural gas exploration and production activities involving hydraulic fracturing by, among other things, promulgating
well completion requirements, imposing controls on storage, recycling and disposal of flowback fluids, and increasing reporting
obligations. In addition, concerns related to the impacts from hydraulic fracturing have led several states to ban new natural gas
development or to impose moratoria on use of hydraulic fracturing in various sensitive areas, including some areas overlying the
Marcellus Shale. Similar action could be taken to preclude or limit natural gas development in other locations.
Recent seismic events have been observed in some areas (including Oklahoma, Ohio and Texas) where hydraulic fracturing
has taken place. Some scientists believe the increased seismic activity may result from deep well fluid injection associated with
use of hydraulic fracturing. Additional regulatory measures designed to minimize or avoid damage to geologic formations may
be imposed to address such concerns.
Concerns regarding climate change have led the Congress, various states and environmental agencies to consider a number
of initiatives to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. Among other things, in
the absence of new federal legislation, the USEPA promulgated regulations imposing reporting and other requirements on sources
of significant emissions of greenhouse gases. Stricter regulations of greenhouse gases could require us to incur costs to reduce
emissions of greenhouse gases associated with our operations, or could adversely affect demand for the oil and natural gas we
produce. In addition, climate change that results in physical effects such as increased frequency and severity of storms, floods
and other climatic events, could disrupt our exploration and production operations and cause us to incur significant costs in
preparing for and responding to those effects.
Although it is not possible at this time to predict the final outcome of the USEPA's study or the requirements of any
additional federal or state legislation or regulation regarding hydraulic fracturing, management of drilling fluids, well integrity
requirements or climate change, any new federal or state restrictions imposed on oil and gas exploration and production activities
in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay
our ability to develop oil and natural gas reserves. In addition to increased regulation of our business, we may also experience an
increase in litigation seeking damages as a result of heightened public concerns related to air quality, water quality, and other
environmental impacts.
The adoption of derivatives legislation by Congress, and implementation of that legislation by federal agencies, could have an
adverse impact on our ability to mitigate risks associated with our business.
On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or
the Dodd-Frank Reform Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter
derivatives market and entities that participate in that market. The legislation required the Commodities Futures Trading
Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation, which they have
done since late 2010. The CFTC has introduced dozens of proposed rules coming out of the Dodd-Frank Reform Act, and has
promulgated numerous final rules based on those proposals. The effect of the proposed rules and any additional regulations on
our business is not yet entirely clear, but it is increasingly clear that the costs of derivatives-based hedging for commodities will
likely increase for all market participants. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users
from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not
the intent of the Act to require margin from end users, the exemption is not in the Act. While rules proposed by the CFTC and
federal banking regulators appear to allow for non-cash collateral and certain exemptions from margin for end users, the rules are
not final and uncertainty remains. The full range of new Dodd-Frank requirements to be enacted, to the extent applicable to us or
our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments
we use to mitigate and otherwise manage our financial and commercial risks related to fluctuations in oil and natural gas prices.
In addition, final rules were promulgated by the CFTC imposing federally-mandated position limits covering a wide range of
derivatives positions, including non-exchange traded bilateral swaps related to commodities including oil and natural gas. These
position limit rules were vacated by a Federal court in September 2012, and the CFTC has appealed that decision and could re-
promulgate the rules in a manner that addresses the defects identified by the court. If these position limits rules go into effect in
the future, they are likely to increase regulatory monitoring and compliance costs for all market participants, even where a given
trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-
Frank Reform Act, including stringent new reporting requirements for derivatives positions and detailed criteria that must be
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satisfied to continue to enter into uncleared swap transactions, could have a material impact on our derivatives trading and hedging
activities in the form of increased transaction costs and compliance responsibilities. Any of the foregoing consequences could
have a material adverse effect on our financial position, results of operations and cash flows.
Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of
operations and cash flows.
From time to time legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These
proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development
costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and
development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period
for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar
changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development,
could adversely affect our business, financial condition, results of operations and cash flows.
We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on
operations.
We operate in the highly competitive areas of oil and natural gas exploration, development and production. Factors that
affect our ability to compete successfully in the marketplace include:
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the availability of funds and information relating to a property;
the standards established by us for the minimum projected return on investment; and
the transportation of natural gas.
Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major
interstate and intrastate pipelines and national and local natural gas gatherers, many of which possess greater financial and other
resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition
and results of operations may be adversely affected.
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to
wells scheduled to be drilled within five years of the date of booking. This requirement may limit our potential to book additional
proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved
undeveloped reserves if we do not drill on those reserves within the required five-year time frame. We removed approximately
4.3 Bcfe and 5.5 Bcfe of proved undeveloped reserves in 2013 and 2012, respectively, as a result of the five year rule. These
write-downs represented approximately 1% and 2% of the respective total year-end proved reserves at December 31, 2013 and
2012.
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved
reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our
reserve report. These differences may be material.
Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were
prepared by Ryder Scott Company, L.P., our independent petroleum and geological engineers, we are ultimately responsible for
the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations
of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from other similar producing wells;
the assumed effects of regulations by governmental agencies;
assumptions concerning future oil and natural gas prices; and
assumptions concerning future operating costs, severance and excise taxes, development costs and work-over and
remedial costs.
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Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those
assumed in estimating proved reserves:
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the quantities of oil and natural gas that are ultimately recovered;
the production and operating costs incurred;
the amount and timing of future development expenditures; and
future oil and natural gas sales prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same
available data. Historically, the difference between our actual production and the production estimated in a prior year's reserve
report has not been material. Our 2013 production, excluding the impact from the Gulf of Mexico Acquisition, was approximately
8% greater than amounts projected in our 2012 reserve report. We cannot assure you that these differences will not be material in
the future.
Approximately 33% of our estimated proved reserves at December 31, 2013 are undeveloped and 8% were developed,
non-producing. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The
reserve data assumes that we will make significant capital expenditures to develop and produce our reserves. Although we have
prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry
standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual
results will be as estimated. In addition, the recovery of undeveloped reserves is generally subject to the approval of development
plans and related activities by applicable state and/or federal agencies. Statutes and regulations may affect both the timing and
quantity of recovery of estimated reserves. Such statutes and regulations, and their enforcement, have changed in the past and may
change in the future, and may result in upward or downward revisions to current estimated proved reserves.
You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated
oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved
reserves at December 31, 2013 are based on twelve-month average prices and costs as of the date of the estimate. These prices
and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes
in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash
flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties
will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount
factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with
accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and
the risks associated with our operations or the oil and natural gas industry in general will affect the accuracy of the 10% discount
factor.
We may be unable to successfully identify, execute or effectively integrate future acquisitions, which may negatively affect our
results of operations.
Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue
to pursue acquisitions in the future. In the last several years, we have pursued and consummated acquisitions that have provided
us opportunities to grow our production and reserves. Although we regularly engage in discussions with, and submit proposals to,
acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate
acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the
acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions
and the integration of acquired business operations may require a disproportionate amount of management's attention and our
resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on
reasonable terms, any new businesses may not generate revenues comparable to our existing business, the anticipated cost
efficiencies or synergies may not be realized and these businesses may not be integrated successfully or operated profitably. The
success of any acquisition will depend on a number of factors, including the ability to estimate accurately the recoverable volumes
of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental
liabilities. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our
results of operations.
Even though we perform due diligence reviews (including a review of title and other records) of the major properties we
seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not
feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. However,
even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become
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familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may
assume certain environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery
of any material liabilities associated with our acquisitions could harm our results of operations.
In addition, acquisitions of businesses may require additional debt or equity financing, resulting in additional leverage
or dilution of ownership. Our bank credit facility contains certain covenants that limit, or which may have the effect of limiting,
among other things acquisitions, capital expenditures, the sale of assets and the incurrence of additional indebtedness.
Hedging production may limit potential gains from increases in commodity prices or result in losses.
We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices
and to achieve more predictable cash flow. Our hedges at December 31, 2013 are in the form of swaps placed with the commodity
trading branches of JPMorgan Chase Bank and Wells Fargo Bank, N.A., both of which participate in our bank credit facility. We
cannot assure you that these or future counterparties will not become credit risks in the future. Hedging arrangements expose us
to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual
obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual
prices received. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices
for oil and natural gas. Oil and natural gas hedges increased our total oil and gas sales by approximately $0.9 million, $9.1 million
and $2.4 million during 2013, 2012 and 2011, respectively. We cannot assure you that the hedging transactions we have entered
into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials
(particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs,
equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand
for oil and natural gas. In accordance with customary industry practice, we rely on independent third-party service providers to
provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, raw materials (particularly sand
and other proppants), supplies, drilling rig crews and other personnel, trucking services, tubulars, fracking and completion services
and production equipment, including equipment and personnel related to horizontal drilling activities, could delay or restrict our
exploration and development operations, which in turn could impair our financial condition and results of operations.
The loss of key management or technical personnel could adversely affect our ability to operate.
Our operations are dependent upon a diverse group of key senior management and technical personnel. In addition, we
employ numerous other skilled technical personnel, including geologists, geophysicists and engineers that are essential to our
operations. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. The unexpected
loss of the services of one or more of any of these key management or technical personnel could have an adverse effect on our
operations.
Operating hazards may adversely affect our ability to conduct business.
Our operations are subject to risks inherent in the oil and natural gas industry, such as:
•
•
•
•
•
unexpected drilling conditions including blowouts, cratering and explosions;
uncontrollable flows of oil, natural gas or well fluids;
equipment failures, fires or accidents;
pollution and other environmental risks; and
shortages in experienced labor or shortages or delays in the delivery of equipment.
These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and
equipment, pollution and other environmental damage and suspension of operations. Our offshore operations are also subject to
a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more
extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage
or result in the interruption or termination of operations.
28
Environmental compliance costs and environmental liabilities could have a material adverse effect on our financial condition
and operations.
Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental protection. These laws and regulations may:
•
•
•
•
•
require the acquisition of permits before drilling commences;
restrict the types, quantities and concentration of various substances that can be released into the environment from
drilling and production activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and
impose substantial liabilities for pollution resulting from our operations.
The trend toward stricter requirements and standards in environmental legislation and regulation is likely to continue.
Our drilling plans may be delayed, modified or precluded as a result of new or modified environmental mandates, including those
imposed to protect the American Burying Beetle and other endangered species that may be present in the vicinity of our operations.
The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs,
as well as on the oil and natural gas industry in general.
Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by
previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could
have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our
operations, including limited coverage for sudden and accidental environmental damages, but this insurance may not extend to
the full potential liability that could be caused by sudden and accidental environmental damages and further may not cover
environmental damages that occur over time. Accordingly, we may be subject to liability or may lose the ability to continue
exploration or production activities upon substantial portions of our properties if certain environmental damages occur.
We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability
of these non-operated properties.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise
influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and
development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside
of our control, including the operator's:
•
•
•
•
•
timing and amount of capital expenditures;
expertise and diligence in adequately performing operations and complying with applicable agreements;
financial resources;
inclusion of other participants in drilling wells; and
use of technology.
As a result of any of the above or an operator's failure to act in ways that are in our best interest, our allocated production
revenues and results of operations could be adversely affected.
Ownership of working interests and overriding royalty interests in certain of our properties by certain of our officers and
directors potentially creates conflicts of interest.
Certain of our executive officers and directors or their respective affiliates are working interest owners or overriding
royalty interest owners in certain properties. In their capacity as working interest owners, they are required to pay their proportionate
share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding
royalty interest owners they are entitled to receive their proportionate share of revenues in the normal course of business. There
is a potential conflict of interest between us and such officers and directors with respect to the drilling of additional wells or other
development operations with respect to these properties.
29
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations
information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create
erroneous information in our hardware or software network infrastructure, possible consequences include our loss of
communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process
commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have
a material adverse effect on our business.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may
adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.
If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and
natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and
natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if
infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase
as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Risks Relating to Our Outstanding Common Stock
Our stock price could be volatile, which could cause you to lose part or all of your investment.
The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to
the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities
of other energy companies, has been and may continue to be highly volatile. During 2013, the sales price of our stock ranged from
a low of $3.55 per share (on February 28, 2013) to a high of $5.39 per share (on January 23, 2013). Factors such as announcements
concerning changes in prices of oil and natural gas, the success of our acquisition, exploration and development activities, the
availability of capital, and economic and other external factors, as well as period-to-period fluctuations and financial results, may
have a significant effect on the market price of our common stock.
From time to time, there has been limited trading volume in our common stock. In addition, there can be no assurance
that there will continue to be a trading market or that any securities research analysts will continue to provide research coverage
with respect to our common stock. It is possible that such factors will adversely affect the market for our common stock.
Issuance of shares in connection with financing transactions or under stock incentive plans will dilute current stockholders.
We have issued 1,495,000 shares of Series B Preferred Stock, which are presently convertible into 5,147,734 shares of
our common stock. In addition, pursuant to our stock incentive plan, our management is authorized to grant stock awards to our
employees, directors and consultants. You will incur dilution upon the conversion of the Series B Preferred Stock, the exercise of
any outstanding stock awards or the grant of any restricted stock. In addition, if we raise additional funds by issuing additional
common stock, or securities convertible into or exchangeable or exercisable for common stock, further dilution to our existing
stockholders will result, and new investors could have rights superior to existing stockholders.
The number of shares of our common stock eligible for future sale could adversely affect the market price of our stock.
At December 31, 2013, we had reserved approximately 1.9 million shares of common stock for issuance under outstanding
options and approximately 5.1 million shares issuable upon conversion of the Series B Preferred Stock. All of these shares of
common stock are registered for sale or resale on currently effective registration statements. We may issue additional restricted
securities or register additional shares of common stock under the Securities Act in the future. The issuance of a significant number
of shares of common stock upon the exercise of stock options, the granting of restricted stock or the conversion of the Series B
Preferred Stock, or the availability for sale, or sale, of a substantial number of the shares of our common stock eligible for future
sale under effective registration statements, under Rule 144 or otherwise, could adversely affect the market price of the common
stock.
Provisions in our certificate of incorporation and bylaws could delay or prevent a change in control of our company, even if
that change would be beneficial to our stockholders.
Certain provisions of our certificate of incorporation and bylaws may delay, discourage, prevent or render more difficult
an attempt to obtain control of our company, whether through a tender offer, business combination, proxy contest or otherwise.
These provisions include:
•
the charter authorization of “blank check” preferred stock;
30
•
•
•
provisions that directors may be removed only for cause, and then only on approval of holders of a majority of the
outstanding voting stock;
a restriction on the ability of stockholders to call a special meeting and take actions by written consent; and
provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action
at annual meetings of our stockholders.
We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.
We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations
for the future operation and development of our business. We are currently restricted from paying dividends on our common stock
by our bank credit facility, the indenture governing the 10% senior notes and, in some circumstances, by the terms of our Series
B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.
Item 1B Unresolved Staff Comments
None
Item 3.
Legal Proceedings
PetroQuest is involved in litigation relating to claims arising out of its operations in the normal course of business,
including worker’s compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are
covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Management believes
that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material
adverse effect on PetroQuest’s business or financial position.
Item 4.
Mine Safety Disclosures
Not applicable.
31
PART II
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
The following graph illustrates the yearly percentage change in the cumulative stockholder return on our common stock,
compared with the cumulative total return on the NYSE/AMEX Stock Market (U.S. Companies) Index, the NYSE Stocks—Crude
Petroleum and Natural Gas Index and the Morningstar Oil and Gas E&P Index (added this year for additional reference), for the
five years ended December 31, 2013.
Comparison of 5 Year Cumulative Total Return
Assumes Initial Investment of $100
December 31, 2013
PetroQuest Energy,
Inc.
NYSE/AMEX/
NASDAQ Market
(US Companies)
NYSE Stocks (SIC
1310-1319 US
Companies) Crude
Petroleum and
Natural Gas
Morningstar Oil &
Gas E&P Index
12/31/2008
12/31/2009
12/31/2010
12/31/2011
12/31/2012
12/31/2013
$100.00
90.68
111.39
97.63
73.22
63.91
$100.00
124.87
146.97
148.55
171.78
225.94
32
$100.00
147.61
172.27
160.57
152.25
193.44
$100.00
145.52
182.68
166.65
163.40
196.19
Market Price of and Dividends on Common Stock
Our common stock trades on the New York Stock Exchange under the symbol “PQ.” The following table lists high and
low sales prices per share for the periods indicated:
2012
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2013
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
$
$
High
7.39 $
6.46
7.05
7.00
5.39 $
5.10
4.74
4.93
Low
5.41
4.26
4.82
4.69
3.55
3.85
3.87
3.63
As of February 27, 2014, there were 287 common stockholders of record.
We have never paid a dividend on our common stock, cash or otherwise, and intend to retain our cash flow from operations
for the future operation and development of our business. In addition, under our bank credit facility, the indenture governing the
10% senior notes, and, in some circumstances, the terms of our Series B Preferred Stock, we are restricted from paying cash
dividends on our common stock. The payment of future dividends, if any, will be determined by our Board of Directors in light
of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements,
business conditions and other factors. See Item 1A. “Risk Factors – Risks Relating to our Outstanding Common Stock – We do
not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.”
The following table sets forth certain information with respect to repurchases of our common stock during the quarter
ended December 31, 2013.
Total Number of
Shares
Purchased (1)
Average Price
Paid Per Share
— $
57,145 $
— $
—
4.18
—
Total Number of
Shares Purchased
as Part of
Publicly
Announced Plan
or Program
Maximum Number (or
Approximate Dollar
Value) of Shares that May
be Purchased Under the
Plans or Programs
—
—
—
—
—
—
October 1—October 31, 2013
November 1—November 30, 2013
December 1—December 31, 2013
(1) All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.
33
Item 6.
Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information for the Company.
The financial information for each of the five years in the period ended December 31, 2013 has been derived from the audited
Consolidated Financial Statements of the Company for such periods. The information should be read in conjunction with
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial
Statements and notes thereto. The following information is not necessarily indicative of future results of the Company. All amounts
are stated in U.S. dollars unless otherwise indicated.
2013
2012 (1)
2011 (2)
2010
2009 (3)
Year Ended December 31,
Average sales price per Mcfe
Revenues
Net income (loss) available to common stockholders
$
4.80
182,870
8,943
Net income (loss) available to common stockholders
per share:
(in thousands except per share and per Mcfe data)
$
$
$
4.17
141,591
(137,218)
5.32
160,700
5,409
5.78
179,263
41,987
$
6.39
218,684
(95,330)
Basic
Diluted
Oil and gas properties, net
Total assets
Long-term debt
Stockholders’ equity
0.14
0.14
581,242
667,190
425,000
99,095
(2.20)
(2.20)
333,946
433,403
200,000
87,591
0.08
0.08
405,351
516,166
150,000
222,390
0.67
0.66
312,940
439,517
150,000
208,162
(1.72)
(1.72)
321,875
410,459
178,267
162,105
(1) The year ended December 31, 2012 includes a pre-tax ceiling test write-down of $137.1 million.
(2) The year ended December 31, 2011 includes a pre-tax ceiling test write-down of $18.9 million.
(3) The year ended December 31, 2009 includes a pre-tax ceiling test write-down of $156.1 million.
Item 7.
Overview
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with operations in
Oklahoma, Texas, and the Gulf Coast Basin. We seek to grow our production, proved reserves, cash flow and earnings at low
finding and development costs through a balanced mix of exploration, development and acquisition activities. From the
commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore
properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During
2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower
risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk
profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift
capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our
drilling program across multiple basins.
We have successfully diversified into onshore, longer life basins in Oklahoma and Texas through a combination of
selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in Texas through 2013,
we have invested approximately $1.1 billion into growing our longer life assets. During the ten year period ended December 31,
2013, we have realized a 95% drilling success rate on 918 gross wells drilled. Comparing 2013 metrics with those in 2003, the
year we implemented our diversification strategy, we have grown production by 294% and estimated proved reserves by 262%.
At December 31, 2013, 81% of our estimated proved reserves and 63% of our 2013 production were derived from our longer life
assets.
As a result of the impact of low natural gas prices on our revenues and cash flow, we have focused on growing our reserves
and production through a balanced drilling budget with an increased emphasis on growing our oil and natural gas liquids production.
In May 2010, we entered into the JDA, which provided us with $85 million in cash during 2010 and 2011, along with a drilling
carry that we have utilized since May 2010 to enhance economic returns by reducing our share of capital expenditures in the
Woodford Shale and the Mississippian Lime. During 2013, we closed the Gulf of Mexico Acquisition. The aggregate purchase
34
price of the Gulf of Mexico Acquisition was $188.8 million and it contributed 30.5 Bcfe to our estimated proved reserves at
December 31, 2013 as well as 4.5 Bcfe of production during 2013. As a result of the JDA, the Gulf of Mexico Acquisition and
the success of our drilling programs in each of our operating areas, we have grown our estimated proved reserves by 69% and
production by 11% since year end 2009, including a 36% increase in our oil and natural gas liquids production during 2013.
Gulf of Mexico Acquisition
On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million,
reflecting an effective date of January 1, 2013. The Gulf of Mexico Acquisition was financed with the issuance of an additional
$200 million in aggregate principal amount of our 10% Senior Notes due 2017. The transaction included 16 gross wells located
on seven platforms.
During 2013, the Acquired Assets contributed 4.5 Bcfe of total production, including 235,000 barrels of oil, and added
30.5 Bcfe of estimated proved reserves as of December 31, 2013. As a result of the Gulf of Mexico Acquisition, our acreage
position in the Gulf Coast Basin increased 23% to 46,801 net acres. See "Note 2 - Acquisition" in Item 8. Financial Statements
and Supplementary Data for additional details related to this transaction.
We believe the Gulf of Mexico Acquisition represents both a strategic and transformative transaction for us. This
transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop
our longer-life resource assets. As evidenced by the larger percentage of our production and estimated proved reserves now located
in our longer lived basins, we have successfully leveraged our Gulf Coast free cash flow to help fund our substantial diversification
efforts over the past several years. We plan to utilize a portion of the free cash flow generated from these acquired properties to
accelerate the development of our Woodford Shale and Cotton Valley resource plays. In addition, based upon our experience and
successful track record in exploiting reservoirs in the Gulf Coast Basin and Gulf of Mexico, we believe that we will be able to
create value above the current estimated proved reserves associated with the Acquired Assets.
Critical Accounting Policies
Reserve Estimates
Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at
which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated
by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent
projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and
quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically
recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other producing areas, the assumed effect of regulations
by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes,
development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations
may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in
the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of
our oil and gas properties and/or the rate of depletion of such oil and gas properties.
Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new
technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the
existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence
and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates.
Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending
date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average is also used to measure ceiling
test impairments and to compute depreciation, depletion and amortization.
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition,
exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and
developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire
35
property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and
geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs
of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed
in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments
of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between
capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate
to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These
costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible
impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon
production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the
amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated
properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion
expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these
estimates could have an impact on our future earnings.
We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities.
The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do
not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest
costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective
borrowing rate.
Capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization ("DD&A") and
related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of
cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for
related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-
down of oil and gas properties in the quarter in which the excess occurs.
Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from estimated
proved oil and gas reserves will change in the near term. If oil or gas prices decline, even for only a short period of time, or if we
have downward revisions to our estimated proved reserves, it is possible that further write-downs of oil and gas properties could
occur in the future.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering
systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our
properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market
demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because
these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make
estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the
timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.
Derivative Instruments
We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity
derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance
sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other
comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because
the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the
fair value of the derivative are recorded in the income statement as derivative income (expense).
Our hedges are specifically referenced to NYMEX prices for oil and natural gas. We evaluate the effectiveness of our
hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between
NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine
if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges
will be settled. At December 31, 2013, our derivative instruments were designated effective cash flow hedges.
36
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future
NYMEX prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using
an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the
derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets
and an estimate of our default risk for derivative liabilities.
Results of Operations
The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These
historical results are not necessarily indicative of results to be expected in future periods.
Production:
Oil (Bbls)
Gas (Mcf)
Ngl (Mcfe)
Total Production (Mcfe)
Sales:
Total oil sales
Total gas sales
Total ngl sales
Total oil and gas sales
Average sales prices:
Oil (per Bbl)
Gas (per Mcf)
Ngl (per Mcfe)
Per Mcfe
Year Ended December 31,
2013
2012
2011
680,980
29,225,843
4,754,223
38,065,946
70,476,065
87,449,370
24,878,243
182,803,678
103.49
2.99
5.23
4.80
$
$
$
520,590
27,466,228
3,366,774
33,956,542
56,635,786
63,535,262
21,262,236
141,433,284
108.79
2.31
6.32
4.17
$
$
$
572,096
24,462,933
2,287,846
30,183,355
60,064,426
78,664,373
21,756,917
160,485,716
104.99
3.22
9.51
5.32
$
$
$
The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of
$1,098,000, $6,846,000 and $2,609,000, oil hedges of ($232,000), $1,529,000 and ($192,000), and Ngl hedges of $61,000, $722,000
and zero for the twelve months ended December 31, 2013, 2012 and 2011, respectively.
Comparison of Results of Operations for the Years Ended December 31, 2013 and 2012
Net income (loss) available to common stockholders totaled $8,943,000 and ($137,218,000) for the years ended December 31,
2013 and 2012, respectively. The primary fluctuations were as follows:
Production Total production increased 12% during the year ended December 31, 2013 as compared to the 2012 period. Gas
production during the year ended December 31, 2013 increased 6% from the 2012 period. The increase in gas production was
primarily the result of added production from the Gulf of Mexico Acquisition which closed on July 3, 2013. Additionally, gas
production increased as a result of the successful drilling programs in our La Cantera field and our liquids rich Woodford acreage.
Partially offsetting these increases were decreases in gas production due to normal production declines at our dry gas Oklahoma
fields as well as certain of our legacy Gulf of Mexico fields in addition to the loss of production resulting from the sale of our
Fayetteville assets in December 2012. As a result of a full year of production from the wells acquired in the Gulf of Mexico
Acquisition and increased drilling activity planned for 2014, we expect our average daily gas production in 2014 to increase as
compared to 2013.
Oil production during the year ended December 31, 2013 increased 31% as compared to the 2012 period due primarily to added
production from the Gulf of Mexico Acquisition as well as the continued success of our La Cantera field. Partially offsetting these
increases were decreases as a result of continued normal production declines in certain of our legacy Gulf of Mexico and East
Texas fields. As a result of a full year of production from the wells acquired in the Gulf of Mexico Acquisition, we expect our
average daily oil production to be significantly higher during 2014 as compared to 2013.
Ngl production during the year ended December 31, 2013 increased 41% from the 2012 period due to the success experienced in
our La Cantera field and the liquids rich portion of our Oklahoma properties, as well as added production from the Gulf of Mexico
Acquisition. Partially offsetting these increases were decreases as a result of normal production declines at certain of our legacy
Gulf of Mexico fields. As a result of the increase in drilling activity planned for 2014 as well as a full year of production from
37
the wells acquired in the Gulf of Mexico Acquisition, we expect our daily Ngl production for 2014 to increase significantly
compared to that of 2013.
Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2013 were $2.99 as
compared to $2.31 for the 2012 period. Average oil prices per Bbl for the year ended December 31, 2013 were $103.49 as compared
to $108.79 for the 2012 period and average Ngl prices per Mcfe were $5.23 for the year ended December 31, 2013, as compared
to $6.32 for the 2012 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2013 were 15%
higher than the prices received during the 2012 period.
Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2013 increased 29% to
$182,804,000, as compared to oil and gas sales of $141,433,000 during the 2012 period. The increased revenue during 2013 was
primarily the result of higher average realized prices for our production during 2013 as well as increased production as discussed
above.
Expenses Lease operating expenses for the year ended December 31, 2013 totaled $43,743,000 as compared to $38,890,000 during
the 2012 period. Per unit lease operating expenses totaled $1.15 per Mcfe during both of the twelve month periods ended
December 31, 2013 and 2012. We expect the absolute amount of lease operating expenses to increase during 2014 as compared
to 2013 as a result of the Gulf of Mexico Acquisition but we expect per unit lease operating costs to approximate per unit amounts
in 2013.
Production taxes for the year ended December 31, 2013 totaled $3,950,000 as compared to $885,000 during the 2012 period. The
significant reduction during the 2012 period was the result of recording a receivable of $2,717,000 during June 2012 for refunds
relative to severance tax previously paid on our Oklahoma horizontal wells that we are receiving incrementally through June,
2015. Because the majority of the assets purchased in the Gulf of Mexico Acquisition are located in Federal waters and are therefore
not subject to production taxes, we do not expect a meaningful change to our production taxes during 2014 as compared to 2013.
General and administrative expenses during the year ended December 31, 2013 totaled $26,512,000 as compared to $22,957,000
during the 2012 period. Included in general and administrative expenses was non-cash, share-based compensation expense as
follows (in thousands):
Stock options:
Incentive Stock Options
Non-Qualified Stock Options
Restricted stock
Non-cash share-based compensation
Year Ended December 31,
2013
2012
$
$
310
222
3,684
4,216
$
$
786
660
5,464
6,910
General and administrative expenses increased 15% during the year ended December 31, 2013 as compared to the 2012 period.
Included in general and administrative expenses during the 2013 period is $4,018,000 of transaction-related costs related to the
Gulf of Mexico Acquisition. In addition, during 2013, we recognized approximately $895,000 in general and administrative
expenses associated with benefits due under the compensation agreements of the Company's Executive Vice-President and General
Counsel, who passed away unexpectedly in September 2013. We capitalized $13,514,000 of general and administrative costs
during the year ended December 31, 2013 as compared to $11,925,000 during the comparable 2012 period. General and
administrative expenses in 2014 are expected to be lower than 2013 due to these non-recurring items.
DD&A expense on oil and gas properties for the year ended December 31, 2013 totaled $69,357,000, or $1.82 per Mcfe, as
compared to $59,496,000, or $1.75 per Mcfe, during the comparable 2012 period. The increase in the per unit DD&A rate is
primarily the result of the Gulf of Mexico Acquisition, which had a higher cost per unit as compared to our overall amortization
base. After taking into effect the Gulf of Mexico Acquisition, we expect our DD&A rate for 2014 to be higher than the full year
rate during 2013.
At December 31, 2012, the prices used in computing the estimated future net cash flows from our estimated proved reserves,
including the effect of hedges in place at that date, averaged $2.21 per Mcf of natural gas, $102.81 per barrel of oil, and $6.07 per
Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved
reserves and estimated future net cash flows, we recognized ceiling test write-downs of $137,100,000 during the year ended
December 31, 2012. No such ceiling test write-down occurred during 2013.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $21,886,000 during the year ended December 31,
2013, as compared to $9,808,000 during 2012. During the year ended December 31, 2013, our capitalized interest totaled $6,570,000
38
as compared to $7,036,000 during the 2012 period. The increase in interest expense was a result of the issuance of an additional
$200 million of 10% senior notes, which were used to finance the Gulf of Mexico Acquisition in addition to increased borrowings
outstanding under our bank credit facility during 2013 as compared to 2012. As a result, we expect interest expense for 2014 to
be higher than that of 2013.
Income tax expense during the year ended December 31, 2013 totaled $320,000, as compared to $1,636,000 during the 2012
period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized,
primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of the ceiling test
write-downs recognized during 2012, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss
has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our
deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance
for a portion of our deferred tax asset. The valuation allowance was $45,531,000 as of December 31, 2013.
Comparison of Results of Operations for the Years Ended December 31, 2012 and 2011
Net income (loss) available to common stockholders totaled ($137,218,000) and $5,409,000 for the years ended December 31,
2012 and 2011, respectively. The primary fluctuations were as follows:
Production Total production increased 13% during the year ended December 31, 2012 as compared to the 2011 period. Gas
production during the year ended December 31, 2012 increased 12% from the 2011 period. The increase in gas production was
primarily the result of the success of our drilling programs in the Woodford Shale in Oklahoma, the Carthage field in East Texas,
and the La Cantera field in South Louisiana. Gas production also increased at our West Cameron Block 402 well due to a successful
recompletion during the fourth quarter of 2011. Partially offsetting these increases were normal production declines particularly
in our Gulf Coast region.
Oil production during the year ended December 31, 2012 decreased 9% as compared to the 2011 period due primarily to continued
normal production declines in our onshore Louisiana and offshore Gulf of Mexico fields. Partially offsetting these decreases were
increases from the inception of production from our La Cantera field during March 2012, our Eagle Ford Shale field where five
new wells commenced production during the third and fourth quarters of 2012 and at our Mississippian Lime field where initial
oil production from our first wells began during the second quarter of 2012 with four additional wells beginning production during
the fourth quarter. Additionally, oil production increased at our Ship Shoal field as a result of three successful recompletions
performed during the fourth quarter of 2012.
Ngl production during the year ended December 31, 2012 increased 47% from the 2011 period due to the inception of production
from our La Cantera field, the liquids rich portion of our Oklahoma properties, and an increase in production at our Carthage field
in East Texas. These increases were partially offset by the normal production declines particularly in our Gulf Coast region.
Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2012 were $2.31 as
compared to $3.22 for the 2011 period. Average oil prices per Bbl for the year ended December 31, 2012 were $108.79 as compared
to $104.99 for the 2011 period and average Ngl prices per Mcfe were $6.32 for the year ended December 31, 2012, as compared
to $9.51 for the 2011 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2012 were 22%
lower than the prices received during the 2011 period.
Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2012 decreased 12%
to $141,433,000, as compared to oil and gas sales of $160,486,000 during the 2011 period. The decreased revenue during 2012
was primarily the result of lower natural gas and Ngl prices as well as reduced oil production during the period.
Expenses Lease operating expenses for the year ended December 31, 2012 totaled $38,890,000 as compared to $38,571,000 during
the 2011 period. Per unit lease operating expenses totaled $1.15 per Mcfe during the twelve month period ended December 31,
2012 as compared to $1.28 during the 2011 period. Per unit lease operating expenses decreased primarily due to the increase in
overall produced volumes during the period.
Production taxes for the year ended December 31, 2012 totaled $885,000 as compared to $3,100,000 during the 2011 period. The
significant decrease during the 2012 period was the result of recording a receivable of $2,717,000 during June 2012 for refunds
relative to severance tax previously paid on our Oklahoma horizontal wells that we expect to receive over the next three years.
Beginning in July 2012, we are no longer required to submit the full rate of Oklahoma severance tax on those wells qualifying for
the horizontal tax credit.
General and administrative expenses during the year ended December 31, 2012 totaled $22,957,000 as compared to $20,436,000
during the 2011 period. Included in general and administrative expenses was non-cash share-based compensation expense as
follows (in thousands):
39
Stock options:
Incentive Stock Options
Non-Qualified Stock Options
Restricted stock
Non-cash share-based compensation
Year Ended December 31,
2012
2011
$
$
786
660
5,464
6,910
$
$
493
703
3,637
4,833
General and administrative expenses increased 12% during the year ended December 31, 2012 as compared to the comparable
period of 2011 primarily due to increased non-cash share-based compensation expense during 2012. We capitalized $11,925,000
of general and administrative costs during the year ended December 31, 2012 as compared to $11,176,000 during the comparable
2011 period.
DD&A expense on oil and gas properties for the year ended December 31, 2012 totaled $59,496,000, or $1.75 per Mcfe, as
compared to $57,143,000, or $1.89 per Mcfe, during the comparable 2011 period. The decrease in the per unit DD&A rate is
primarily the result of a decrease in the depletable base due to the ceiling test write-downs recognized during 2012.
At December 31, 2012, the prices used in computing the estimated future net cash flows from our estimated proved reserves,
including the effect of hedges in place at that date, averaged $2.21 per Mcf of natural gas, $102.81 per barrel of oil, and $6.07 per
Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved
reserves and estimated future net cash flows, we recognized ceiling test write-downs of $137,100,000 during the year ended
December 31, 2012. We also recognized a ceiling test write-down of $18,907,000 during the twelve months ended December 31,
2011.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $9,808,000 during the year ended December 31,
2012, as compared to $9,648,000 during 2011. During the year ended December 31, 2012, our capitalized interest totaled $7,036,000
as compared to $7,034,000 during the 2011 period.
Income tax expense (benefit) during the year ended December 31, 2012 totaled $1,636,000, as compared to ($1,810,000) during
the 2011 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to
be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
As a result of the ceiling test write-downs recognized, we have incurred a cumulative three-year loss. Because of the impact the
cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the
realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established
a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $50,866,000 as of December 31, 2012.
Liquidity and Capital Resources
We have financed our acquisition, exploration and development activities to date principally through cash flow from
operations, bank borrowings, other credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At
December 31, 2013, we had a working capital deficit of $26.1 million compared to a deficit of $31.3 million at December 31,
2012. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage
our working capital deficit and liquidity position. To the extent our capital expenditures during 2014 exceed our cash flow and
cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of non-
core assets to fund a portion of our drilling budget.
Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the
global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC.
Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow
and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based
in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can
economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under
the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices
and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive
covenants in the indenture governing the Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants
in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our
control, such as oil and natural gas prices.
40
Source of Capital: Operations
Net cash flow from operations decreased from $88.6 million during the year ended December 31, 2012 to $59.9 million
during the 2013 period. The decrease in operating cash flow during 2013 as compared to 2012 was primarily attributable to the
decrease in our accounts payable to vendors, advances from co-owners and the increase to our revenue receivable offset by the
reduction in accounts receivable from our joint partners.
Source of Capital: Debt
On August 19, 2010, we issued $150 million in principal amount of 10% Senior Notes due 2017 (the "Existing Notes")
in a public offering. On July 3, 2013, we issued an additional $200 million in aggregate principal amount of 10% Senior Notes
due 2017. (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to
100% of their face value plus accrued interest from March 1, 2013. The New Notes have terms that, subject to certain exceptions,
are substantially identical to the Existing Notes. The net proceeds from the offering were used to finance the $188.8 million
aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013.
The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend
payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At December 31, 2013,
$11.7 million of interest had been accrued in connection with the March 1, 2014 interest payment and we were in compliance with
all of the covenants contained in the Notes.
We have a Credit Agreement (as amended, the “Credit Agreement” and sometimes referred to elsewhere in this Form
10-K as our "bank credit facility") with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A. and IberiaBank.
The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments
of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement
also allows us to use up to $25 million of the borrowing base for letters of credit. Our bank credit facility matures on October 3,
2016. As of December 31, 2013, we had $75.0 million of borrowings outstanding under (and no letters of credit issued pursuant
to) the Credit Agreement.
The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to our oil and
gas properties as of January 1 and July 1 of each year. On July 3, 2013, the borrowing base was increased from $150 million to
$200 million (subject to the aggregate commitments of the lenders then in effect). As of December 31, 2013, the aggregate
commitments of the lenders is $150 million and can be increased to up to $300 million by either adding new lenders or increasing
the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur
by March 31, 2014. We or the lenders may request two additional borrowing base redeterminations each year. Each time the
borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base
as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or
by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or
is reduced.
The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment
and at least 80% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear
interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments)
or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments).
The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus
0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternate base rate only, the adjusted LIBO rate
is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office
of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted
LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as
selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit
are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary
administrative fees. In addition, we pay commitment fees based on a sliding scale of 0.375% to 0.5% depending on total
commitments.
We are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total
debt to EBITDAX, determined on a rolling four quarter basis, of 3.5 to 1.0, and a minimum ratio of consolidated current assets
to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary
restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business,
international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of
properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit
Agreement permits us to repurchase up to $10 million of our common stock during the term of the Credit Agreement, as long as
41
after giving effect to such repurchase our Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders
at such time. As of December 31, 2013, we were in compliance with all of the covenants contained in the Credit Agreement.
Source of Capital: Issuance of Securities
Our shelf registration statement allows us to publicly offer and sell up to $350 million of any combination of debt securities,
shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance
that we will or could sell any such securities.
Source of Capital: Joint Ventures
In May 2010, we entered into a joint development agreement with WSGP Gas Producing, LLC ("WSGP"), a subsidiary
of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of our Woodford proved undeveloped
reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program.
We received approximately $57.4 million in cash at closing, net of $2.6 million in transaction fees, and an additional $14 million
in each of 2011 and 2012. In addition, since May 2010, WSGP has funded a share of our drilling costs under a drilling program,
which we refer to as the drilling carry. As of December 31, 2013, approximately $51.6 million of drilling carry remained available.
Source of Capital: Divestitures
We do not budget property divestitures; however, we are continuously evaluating our property base to determine if there
are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain non-strategic assets
in order to provide liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We are
currently exploring divestment opportunities for our Mississippian Lime and South Texas assets. We cannot assure you that we
will be able to sell any of our assets in the future.
On December 31, 2012, we sold our non-operated Arkansas assets for a net cash purchase price of $8.5 million. In
January 2013, we sold 50% of our saltwater disposal systems and related surface assets in the Woodford for net proceeds of
approximately $10 million. In December 2013, we sold our non-operated Wyoming assets for a cash purchase price of $1.0
million.
Use of Capital: Exploration and Development
Our 2014 capital budget, which includes capitalized interest and general and administrative costs, is expected to range
between $140 million and $150 million. Because we operate the majority of our drilling activities, we expect to be able to control
the timing of a substantial portion of our capital investments. We plan to fund our capital expenditures with cash flow from
operations and cash on hand. To the extent our capital expenditures during 2014 exceed our cash flow and cash on hand, we plan
to utilize available borrowings under the bank credit facility or proceeds from the potential sale of non-core assets. To the extent
additional capital is required, we may utilize sales of equity or debt securities or we may reduce our capital expenditures to manage
our liquidity position.
Use of Capital: Acquisitions
On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million. The
Acquired Assets include 16 gross wells located on seven platforms.
We believe the acquisition of the Acquired Assets represents both a strategic and transformative transaction for us. This
transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop
our longer life resource assets. We plan to utilize a portion of the free cash flow generated from these acquired properties to
accelerate the development of our Woodford Shale and Cotton Valley resource plays.
We do not budget acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base
or establish positions in new core areas.
We expect to finance our future acquisition activities, if consummated, through cash on hand or available borrowings
under our bank credit facility. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture
arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on
acceptable terms, if at all.
42
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2013 (in thousands):
Total
2014
2015
2016
2017
2018
After 2018
10% senior notes (1)
$ 490,000
$ 35,000
$ 35,000
$ 35,000
$ 385,000
$
— $
Credit Agreement debt (1)
Operating leases (2)
Asset retirement obligations (3)
Purchase commitments (4)
80,581
8,005
48,536
4,563
1,673
1,384
3,113
4,563
1,860
1,452
3,183
—
77,048
1,414
4,469
—
—
1,312
185
—
—
411
3,945
—
—
—
2,032
33,641
—
Total
$ 631,685
$ 45,733
$ 41,495
$ 117,931
$ 386,497
$
4,356
$
35,673
(1) Includes principal and estimated interest.
(2) Consists primarily of leases for office space and office equipment.
(3) Consists of estimated future obligations to abandon our oil and gas properties.
(4) Consists of certain drilling rig and seismic contracts.
Item 7A Quantitative and Qualitative Disclosures About Market Risk
We experience market risks primarily in two areas: interest rates and commodity prices. Because all of our properties are
located within the United States, we believe that our business operations are not exposed to significant market risks relating to
foreign currency exchange risk.
Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected annual sales
volumes for 2014, a 10% decline in the estimated average prices we expect to receive for our crude oil and natural gas production
would result in an approximate $19.7 million decline in our revenues for 2014.
We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of production through
commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the
counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index,
multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this
difference multiplied by the quantity hedged. During the year ended December 31, 2013, we received approximately $0.9 million
from the counterparties to our derivative instruments in connection with net hedge settlements.
We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the
fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions
in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements
even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage
of increases in oil or gas prices above the fixed amount specified in the hedge.
Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or,
if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing
hedge contracts are JPMorgan Chase Bank and Wells Fargo Bank, both of whom are lenders under the Credit Agreement. To the
extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement would
serve as counterparties.
As of December 31, 2013, we had entered into the following gas hedge contracts:
Production Period
Instrument
Type
Daily Volumes
Weighted
Average Price
Natural Gas:
2014
Crude Oil:
January - June 2014
2014
2014
LLS - Louisiana Light Sweet
WTI - West Texas Intermediate
Swap
40,000 Mmbtu
Swap (LLS)
Swap (LLS)
Swap (WTI)
450 Bbls
400 Bbls
350 Bbls
43
$4.12
$100.58
$101.15
$93.26
At December 31, 2013, we recognized a net liability of approximately $1.1 million related to the estimated fair value of
these derivative instruments. Based on estimated future commodity prices as of December 31, 2013, we would realize a $0.7
million loss, net of taxes, as an decrease to oil and gas sales during the next 12 months. This loss is expected to be reclassified
based on the schedule of gas volumes stipulated in the derivative contracts.
During January 2014, we entered into the following additional hedge contract accounted for as a cash flow hedge:
Production Period
Crude Oil:
March - December 2014
Instrument Type
Daily Volumes
Weighted Average Price
Swap
5,000 Mmbtu
$4.285
After executing the above transactions, the Company has approximately 16.1 Bcf of gas volumes, at an average price of
$4.14 per Mcf, and approximately 355,000 barrels of oil volumes at an average price of $98.18 per barrel, hedged for 2014.
Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 18% of our total debt
as of December 31, 2013. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of
December 31, 2013, and assuming a 10% increase in interest rates and no changes in the amount of debt outstanding, the potential
effect on interest expense for 2013 is $0.2 million.
Item 8.
Financial Statements and Supplementary Data
Information concerning this Item begins on page F-1.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer
and Chief Financial Officer, carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures
pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded the following:
i.
that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be
disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such
information is accumulated and communicated to the Company’s management, including the Chief Executive
Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and
ii.
that the Company’s disclosure controls and procedures are effective.
Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will
detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information
otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any
system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting during the quarter ended
December 31, 2013 that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control
over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, and for
performing an assessment of the effectiveness of internal control over financial reporting as of December 31, 2013. Internal control
over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our
system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of
44
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
(ii) 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 (iii) 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.
Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management performed an assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2013 based upon criteria in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (1992 framework). Based on our assessment, management believes that our internal
control over financial reporting was effective as of December 31, 2013 based on these criteria.
Ernst & Young LLP, our independent registered public accounting firm, has issued their report on the effectiveness of
the Company's internal control over financial reporting as of December 31, 2013.
March 5, 2014
/s/ Charles T. Goodson
Charles T. Goodson
Chairman and
Chief Executive Officer
/s/ J. Bond Clement
J. Bond Clement
Executive Vice President-
Chief Financial Officer
45
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
PetroQuest Energy, Inc.
We have audited PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2013, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (1992 framework) (the COSO criteria). PetroQuest Energy, Inc.’s management is responsible for
maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, PetroQuest Energy, Inc. maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2013, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2013 and 2012, and the
related consolidated statements of operations, comprehensive income, cash flows, and stockholders’ equity for each of the three
years in the period ended December 31, 2013 and our report dated March 5, 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New Orleans, Louisiana
March 5, 2014
Item 9B.
Other Information
NONE
Items 10, 11, 12, 13, & 14.
PART III
Pursuant to General Instruction G of Form 10-K, the information concerning Item 10. Directors, Executive Officers
and Corporate Governance, Item 11. Executive Compensation, Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters, Item 13. Certain Relationships and Related Transactions, and Director
Independence and Item 14. Principal Accounting Fees and Services, is incorporated by reference to the information set forth in
the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held May 21, 2014,
to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with the Securities and Exchange Commission.
46
Item 15.
Exhibits, Financial Statement Schedules
(a) 1. FINANCIAL STATEMENTS
PART IV
The following financial statements of the Company and the Report of the Company’s Independent Registered Public
Accounting Firm thereon are included on pages F-1 through F-27 of this Form 10-K:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Operations for the three years ended December 31, 2013
Consolidated Statements of Comprehensive Income for the three years ended December 31, 2013
Consolidated Statements of Cash Flows for the three years ended December 31, 2013
Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2013
Notes to Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is inapplicable or the information is presented in the Financial
Statements or the notes thereto.
47
3.
EXHIBITS:
** 2.1
** 2.2
** 2.3
** 2.4
** 2.5
3.1
3.2
3.3
3.4
3.5
3.6
4.1
4.2
4.3
4.5
4.6
Plan and Agreement of Merger by and among Optima Petroleum Corporation, Optima Energy
(U.S.) Corporation, its wholly-owned subsidiary, and Goodson Exploration Company, NAB
Financial L.L.C., Dexco Energy, Inc., American Explorer, L.L.C. (incorporated herein by reference
to Appendix G of the Proxy Statement on Schedule 14A filed July 22, 1998).
Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration II, L.P. (incorporated herein by reference to Exhibit 2.1 to Form 8-K
filed on June 20, 2013).
Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration III, L.P. (incorporated herein by reference to Exhibit 2.2 to Form 8-K
filed on June 20, 2013).
Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration IV, L.P. (incorporated herein by reference to Exhibit 2.3 to Form 8-K
filed on June 20, 2013).
Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
GOM-H Exploration, LLC (incorporated herein by reference to Exhibit 2.4 to Form 8-K filed on
June 20, 2013).
Certificate of Incorporation of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit
4.1 to Form 8-K filed September 16, 1998).
Certificate of Amendment to Certificate of Incorporation dated May 14, 2008 (incorporated herein
by reference to Exhibit 3.1 to Form 8-K filed June 23, 2009).
Bylaws of PetroQuest Energy, Inc., as amended of December 20, 2007 (incorporated herein by
reference to Exhibit 3.1 to Form 8-K filed December 21, 2007).
Certificate of Domestication of Optima Petroleum Corporation (incorporated herein by reference to
Exhibit 4.4 to Form 8-K filed September 16, 1998).
Certificate of Designations, Preferences, Limitations and Relative Rights of The Series a Junior
Participating Preferred Stock of PetroQuest Energy, Inc. (incorporated herein by reference to
Exhibit A of the Rights Agreement attached as Exhibit 1 to Form 8-A filed November 9, 2001).
Certificate of Designations establishing the 6.875% Series B Cumulative Convertible Perpetual
Preferred Stock, dated September 24, 2007 (incorporated herein by reference to Exhibit 3.1 to Form
8-K filed on September 24, 2007).
Rights Agreement dated as of November 7, 2001 between PetroQuest Energy, Inc. and American
Stock Transfer & Trust Company, as Rights Agent, including exhibits thereto (incorporated herein
by reference to Exhibit 1 to Form 8-A filed November 9, 2001).
Form of Rights Certificate (incorporated herein by reference to Exhibit C of the Rights Agreement
attached as Exhibit 1 to Form 8-A filed November 9, 2001).
Indenture, dated August 19, 2010, between PetroQuest Energy, Inc. and The Bank of New York
Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on
August 19, 2010).
First Supplemental Indenture, dated August 19, 2010, among PetroQuest Energy, Inc., the
Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A.
(incorporated herein by reference to Exhibit 4.3 to Form 8-K filed on August 19, 2010).
Second Supplemental Indenture, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary
Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A.
(incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on July 3, 2013).
48
4.7
†10.1
†10.2
†10.3
†10.4
†10.5
†10.6
†10.7
†10.8
†10.9
†10.10
†10.11
†10.12
10.13
10.14
Registration Rights Agreement, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary
Guarantors identified therein, and J.P. Morgan Securities LLC, as representative of the several
initial purchasers named therein (incorporated herein by reference to Exhibit 4.3 to Form 8-K filed
on July 3, 2013).
PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective May 14, 2008 (the
“Incentive Plan”) (incorporated herein by reference to Appendix A of the Proxy Statement on
Schedule 14A filed April 9, 2008).
Form of Incentive Stock Option Agreement for executive officers (including Charles T. Goodson,
W. Todd Zehnder, Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.)
under the PetroQuest Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit
10.2 to Form 10-K filed February 27, 2009).
Form of Nonstatutory Stock Option Agreement under the PetroQuest Energy, Inc. 1998 Incentive
Plan (incorporated herein by reference to Exhibit 10.3 to Form 10-K filed February 27, 2009).
Form of Restricted Stock Agreement for executive officers (including Charles T. Goodson, W. Todd
Zehnder, Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the
PetroQuest Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit 10.4 to
Form 10-K filed February 27, 2009).
PetroQuest Energy, Inc. Annual Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
Form 8-K filed on May 13, 2010).
PetroQuest Energy, Inc. Annual Incentive Plan, as amended and restated (incorporated herein by
reference to Exhibit 10.1 to Form 8-K filed on June 8, 2010).
PetroQuest Energy, Inc. 2012 Employee Stock Purchase Plan (incorporated herein by reference to
Appendix A to Schedule 14A filed March 28, 2012).
PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to
Exhibit 10.1 to Form 8-K filed November 15, 2012).
PetroQuest Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Appendix A to the
Company’s Definitive Proxy Statement on Schedule 14A filed on April 9, 2013).
Form of Award Notice of Restricted Stock Units - Employees (including Charles T. Goodson, W.
Todd Zehnder, Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under
the PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to
Exhibit 10.2 to Form 8-K filed November 15, 2012).
Form of Award Notice of Restricted Stock Units - Outside Director/Consultant under the
PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to
Exhibit 10.3 to Form 8-K filed November 15, 2012).
Form of Restricted Stock Agreement - Executive Officers (including Charles T. Goodson, W. Todd
Zehnder, Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the
PetroQuest Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit 10.4 to
Form 8-K filed November 15, 2012).
Credit Agreement dated as of October 2, 2008, among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc., JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A.,
Wells Fargo Bank, N.A., and Whitney National Bank (incorporated herein by reference to Exhibit
10.1 to Form 8-K filed October 6, 2008).
First Amendment to Credit Agreement dated as of March 24, 2009, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon New York
Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed March 24, 2009).
49
10.15
10.16
10.17
10.18
10.19
†10.20
†10.21
†10.22
†10.23
†10.24
†10.25
†10.26
†10.27
†10.28
Second Amendment to Credit Agreement dated as of September 30, 2009, among PetroQuest
Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon
New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank
(incorporated herein by reference to Exhibit 10.1 to Form 8-K filed October 1, 2009).
Third Amendment to Credit Agreement dated as of August 5, 2010, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Credit Agricole
Corporate and Investment Bank, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney
National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 6,
2010).
Fourth Amendment to Credit Agreement dated as of October 3, 2011, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells Fargo
Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank (incorporated herein by reference to
Exhibit 10.1 to the Form 8-K filed on October 4, 2011).
Fifth Amendment to Credit Agreement dated as of March 29, 2013, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One,
N.A., IBERIABANK and Whitney Bank (incorporated herein by reference to Exhibit 10.1 to the
Form 8-K filed on March 29, 2013).
Sixth Amendment to Credit Agreement dated as of June 19, 2013, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One,
N.A., IBERIABANK and Whitney Bank (incorporated herein by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on June 20, 2013).
Amended Executive Employment Agreement dated effective as of December 31, 2008, between
Charles T. Goodson and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.1
to Form 8-K filed January 6, 2009).
Amended Executive Employment Agreement dated effective as of December 31, 2008, between W.
Todd Zehnder and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to
Form 8-K filed January 6, 2009).
Amended Executive Employment Agreement dated effective as of December 31, 2008, between
Arthur M. Mixon, III and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.3
to Form 8-K filed January 6, 2009).
Amended Executive Employment Agreement dated effective as of December 31, 2008, between J.
Bond Clement and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.20 to
Form 10-K filed February 27, 2009).
Executive Employment Agreement dated May 8, 2012 between PetroQuest Energy, Inc. and Tracy
Price (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed May 10, 2012).
Executive Employment Agreement dated February 1, 2014 between PetroQuest Energy, Inc. and
Edward E. Abels, Jr. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed February
5, 2014).
Form of Amended Termination Agreement between the Company and each of its executive officers,
including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, and J. Bond Clement
(incorporated herein by reference to Exhibit 10.6 to Form 8-K filed January 6, 2009).
Termination Agreement dated May 8, 2012 between PetroQuest Energy, Inc. and Tracy Price
(incorporated herein by reference to Exhibit 10.2 to Form 8-K filed May 10, 2012).
Termination Agreement dated February 1, 2014 between PetroQuest Energy, Inc. and Edward E.
Abels, Jr. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed February 5, 2014).
50
†10.29
10.30
10.31
10.32
Form of Indemnification Agreement between PetroQuest Energy, Inc. and each of its directors and
executive officers, including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, , J. Bond
Clement, Tracy Price, Edward E. Abels, Jr., William W. Rucks, IV, E. Wayne Nordberg, Michael L.
Finch, W.J. Gordon, III and Charles F. Mitchell, II (incorporated herein by reference to Exhibit
10.21 to Form 10-K filed March 13, 2002).
Form of Surrender and Cancellation Agreement for Directors and Executive Officers (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed on September 16, 2010).
Joint Development Agreement dated May 17, 2010, among PetroQuest Energy, L.L.C., a Louisiana
limited liability company, WSGP Gas Producing, LLC, a Delaware limited liability company, and
NextEra Energy Gas Producing, LLC, a Delaware limited liability company (incorporated herein
by reference to Exhibit 10.2 to Form 10-Q filed on August 5, 2010).
Second Amendment to the Joint Development Agreement dated February 24, 2012, among
PetroQuest Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a
Delaware limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited
liability company (incorporated herein by reference to Exhibit 10.22 to Form 10-K filed March 5,
2012).
14.1
Code of Business Conduct and Ethics (incorporated herein by reference to Exhibit 14.1 to Form
10-K filed March 8, 2006).
*21.1
Subsidiaries of the Company.
*23.1
Consent of Independent Registered Public Accounting Firm.
*23.2
Consent of Ryder Scott Company, L.P.
*31.1
*31.2
*32.1
*32.2
Certification of Chief Executive Officer pursuant to Rule 13-a-14(a) / Rule 15d-14(a),
promulgated under the Securities Exchange Act of 1934, as amended.
Certification of Chief Financial Officer pursuant to Rule 13-a-14(a) / Rule 15d-14(a), promulgated
under the Securities Exchange Act of 1934, as amended.
Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Chief Executive Officer.
Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Chief Financial Officer.
*99.1
Reserve report letter as of December 31, 2013, as prepared by Ryder Scott Company, L.P.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Definitions Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
*
**
Filed herewith.
The registrant agrees to furnish supplementally a copy of any omitted schedule to the Agreements to the SEC upon
request.
†
Management contract or compensatory plan or arrangement
51
(b) Exhibits. See Item 15 (a) (3) above.
(c) Financial Statement Schedules. None
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and natural gas used in this Form 10-K.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate
or natural gas liquids.
Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S.
Minerals Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the
Gulf of Mexico.
Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree
Fahrenheit.
Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole,
the reporting of abandonment to the appropriate agency.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure,
but that, when produced, is in the liquid phase at surface pressure and temperature.
Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for
each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation
procedure.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the
sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive
of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a
service well, or a stratigraphic test well as those items are defined in this section.
Extension well. A well drilled to extend the limits of a known reservoir.
Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns
the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor
is a "farm-out."
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.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have
potential for the discovery of commercial hydrocarbons.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
52
MMBls. Million barrels of crude oil or other liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,
condensate or natural gas liquids.
Ngl. Natural gas liquid.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells, as the case may be.
Possible reserves. Those additional reserves that are less certain to be recovered than probable reserves.
Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of
values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a
full range of possible outcomes and their associated probabilities of occurrence.
Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together
with proved reserves, are as likely as not to be recovered.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of such production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary
economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
Proved area. The part of a property to which proved reserves have been specifically attributed.
Proved oil and gas reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can
be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and
under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing
the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation.
Proved properties. Properties with proved reserves.
Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the
quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved
than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and
economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase
or remain constant than to decrease.
Reliable technology. 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.
Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible,
as of a given date, by application of development projects to known accumulations.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or
gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources. Quantities of oil and 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 to be unrecoverable. Resources include both discovered
and undiscovered accumulations.
Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes
of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection,
observation, or injection for in-situ combustion.
53
Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic
condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.
Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.
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 natural gas and oil regardless of whether such acreage contains proved reserves.
Unproved properties. Properties with no proved reserves
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities
on the property and receive a share of production.
54
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 March 5, 2014.
SIGNATURES
PETROQUEST ENERGY, INC.
By:
/s/ Charles T. Goodson
CHARLES T. GOODSON
Chairman of the Board, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities indicated on March 5, 2014.
By:
By:
By:
By:
By:
By:
By:
/s/ Charles T. Goodson
CHARLES T. GOODSON
Chairman of the Board, President, Chief Executive Officer and Director
(Principal Executive Officer)
/s/ J. Bond Clement
J. BOND CLEMENT
Executive Vice President, Chief Financial Officer, Treasurer
(Principal Financial and Accounting Officer)
/s/ W.J. Gordon, III
W.J. GORDON, III
/s/ Michael L. Finch
MICHAEL L. FINCH
Director
Director
/s/ Charles F. Mitchell, II, M.D. Director
CHARLES F. MITCHELL, II,
M.D.
/s/ E. Wayne Nordberg
E. WAYNE NORDBERG
Director
/s/ William W. Rucks, IV
WILLIAM W. RUCKS, IV
Director
55
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets of PetroQuest Energy, Inc.
Consolidated Statements of Operations of PetroQuest Energy, Inc.
Consolidated Statements of Comprehensive Income of PetroQuest Energy,
Inc.
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc.
Consolidated Statements of Stockholders’ Equity of PetroQuest Energy,
Inc.
Notes to Consolidated Financial Statements
F-1
F-2
F-3
F-4
F-5
F-6
F-7
56
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
PetroQuest Energy, Inc.
We have audited the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2013 and 2012,
and the related consolidated statements of operations, comprehensive income, cash flows and stockholders’ equity for each of the
three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position
of PetroQuest Energy, Inc. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992
framework) and our report dated March 5, 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
New Orleans, Louisiana
March 5, 2014
F-1
PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
ASSETS
Current assets:
Cash and cash equivalents
Revenue receivable
Joint interest billing receivable
Other receivable
Derivative asset
Prepaid drilling costs
Other current assets
Total current assets
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method
Unevaluated oil and gas properties
Accumulated depreciation, depletion and amortization
Oil and gas properties, net
Other property and equipment
Accumulated depreciation of other property and equipment
Total property and equipment
Other assets, net of accumulated amortization of $5,689 and $4,240, respectively
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors
Advances from co-owners
Oil and gas revenue payable
Accrued interest and preferred stock dividend
Asset retirement obligation
Derivative liability
Other accrued liabilities
Total current liabilities
Bank debt
10% Senior Notes
Asset retirement obligation
Other long-term liability
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495
shares
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 63,664
and 62,768 shares, respectively
Paid-in capital
Accumulated other comprehensive income (loss)
Accumulated deficit
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying Notes to Consolidated Financial Statements.
F-2
December 31,
2013
December 31,
2012
$
$
$
9,153
26,568
26,556
—
521
477
8,132
71,407
2,035,899
98,387
(1,553,044)
581,242
13,993
(8,901)
586,334
9,449
667,190
47,341
969
22,664
12,909
3,113
1,617
8,924
97,537
75,000
350,000
45,423
135
$
$
$
14,904
17,742
42,238
9,208
830
1,698
2,964
89,584
1,734,477
71,713
(1,472,244)
333,946
12,370
(7,607)
338,709
5,110
433,403
58,960
20,459
26,175
6,190
2,351
233
6,535
120,903
50,000
150,000
24,909
—
1
1
64
280,711
(1,096)
(180,585)
99,095
667,190
$
63
276,534
521
(189,528)
87,591
433,403
$
PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)
Revenues:
Oil and gas sales
Gas gathering revenue
Expenses:
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
Ceiling test write-down
General and administrative
Accretion of asset retirement obligation
Interest expense
Other income (expense):
Other income (expense)
Derivative income (expense)
Income (loss) from operations
Income tax expense (benefit)
Net income (loss)
Preferred stock dividend
Net income (loss) available to common stockholders
Earnings per common share:
Basic
Net income (loss) per share
Diluted
Net income (loss) per share
Weighted average number of common shares:
Basic
Diluted
Year Ended
December 31,
2013
2012
2011
$
$
182,804
66
182,870
$
141,433
158
141,591
160,486
214
160,700
43,743
3,950
71,445
—
26,512
1,753
21,886
169,289
588
233
821
14,402
320
14,082
5,139
8,943
38,890
885
60,689
137,100
22,957
2,078
9,808
272,407
606
(233)
373
(130,443)
1,636
(132,079)
5,139
$ (137,218) $
38,571
3,100
58,243
18,907
20,436
2,049
9,648
150,954
(1,008)
—
(1,008)
8,738
(1,810)
10,548
5,139
5,409
0.14
0.14
$
$
(2.20) $
0.08
(2.20) $
0.08
63,054
63,208
62,459
62,459
61,937
62,325
$
$
$
See accompanying Notes to Consolidated Financial Statements.
F-3
PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Income
(Amounts in Thousands)
Net income (loss)
Change in fair value of derivatives, net of income tax (expense)
benefit of $309, $2,079 and ($2,388) respectively
Comprehensive income (loss)
Year Ended
December 31,
2012
$ (132,079) $
2013
14,082
(1,617)
12,465
(3,510)
$ (135,589) $
$
$
2011
10,548
5,120
15,668
See accompanying Notes to Consolidated Financial Statements.
F-4
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(Amounts in Thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Deferred tax expense (benefit)
Depreciation, depletion and amortization
Ceiling test write-down
Accretion of asset retirement obligation
Share based compensation expense
Amortization costs and other
Non-cash derivative expense (benefit)
Payments to settle asset retirement obligations
Changes in working capital accounts:
Revenue receivable
Prepaid drilling and pipe costs
Joint interest billing and other receivable
Accounts payable and accrued liabilities
Advances from co-owners
Other
Net cash provided by operating activities
Cash flows used in investing activities:
Investment in oil and gas properties
Investment in other property and equipment
Sale of oil and gas properties
Sale of unevaluated oil and gas properties
Net cash used in investing activities
Cash flows used in financing activities:
Net payments for share based compensation
Deferred financing costs
Payment of preferred stock dividend
Proceeds from bank borrowings
Repayment of bank borrowings
Proceeds from issuance of 10% Senior Notes
Costs to issue 10% Senior Notes
Net cash provided by (used in) financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest
Income taxes
Year Ended
December 31,
2013
2012
2011
$
14,082
$ (132,079) $
10,548
320
71,445
—
1,753
4,216
1,473
(233)
(3,335)
(8,826)
1,221
15,685
(12,865)
(19,490)
(5,592)
59,854
(298,824)
(1,679)
19,913
487
(280,103)
(38)
(320)
(5,139)
73,000
(48,000)
200,000
(5,005)
214,498
(5,751)
14,904
9,153
20,101
12
$
$
$
1,636
60,689
137,100
2,078
6,910
881
233
(2,627)
(1,882)
4,479
3,981
20,916
(13,408)
(316)
88,591
(147,771)
(1,743)
837
8,889
(139,788)
(981)
(42)
(5,139)
102,500
(52,500)
—
—
43,838
(7,359)
22,263
14,904
16,026
105
$
$
$
(1,810)
58,243
18,907
2,049
4,833
625
—
(905)
(2,474)
5,530
(35,252)
34,599
25,904
(1,621)
119,176
(194,536)
(1,286)
14,000
28,461
(153,361)
(1,133)
(517)
(5,139)
22,000
(22,000)
—
—
(6,789)
(40,974)
63,237
22,263
16,017
51
$
$
$
See accompanying Notes to Consolidated Financial Statements.
F-5
PetroQuest Energy Inc.
Consolidated Statements of Stockholders’ Equity
(Amounts in Thousands)
Common
Stock
Preferred
Stock
December 31, 2010
Options exercised
Retirement of shares upon
vesting of restricted stock
Share-based compensation
expense
Derivative fair value
adjustment, net of tax
Preferred stock dividend
Net income
December 31, 2011
Options exercised
Retirement of shares upon
vesting of restricted stock
Share-based compensation
expense
Derivative fair value
adjustment, net of tax
Preferred stock dividend
Net loss
December 31, 2012
Options exercised
Retirement of shares upon
vesting of restricted stock
Share-based compensation
expense
Issuance of shares under
employee stock purchase plan
Derivative fair value
adjustment, net of tax
Preferred stock dividend
Net income
December 31, 2013
$
$
$
$
62
—
—
—
—
—
—
62
—
1
—
—
—
—
63
—
1
—
—
—
—
—
64
$
$
$
$
1
—
—
—
—
—
—
1
—
—
—
—
—
—
1
—
—
—
—
—
—
—
1
Paid-In
Capital
$ 266,907
234
(1,368)
4,833
—
—
—
$ 270,606
260
(1,242)
6,910
—
—
—
$ 276,534
731
(1,057)
4,216
287
—
—
—
$ 280,711
Other
Comprehensive
Income (Loss)
$
(1,089) $
—
$
$
—
—
5,120
—
—
4,031
—
—
—
(3,510)
—
—
521
—
—
—
—
Accumulated
Deficit
Total
Stockholders’
Equity
(57,719) $ 208,162
234
—
—
—
(1,368)
4,833
5,120
—
(5,139)
(5,139)
10,548
10,548
(52,310) $ 222,390
260
—
$
—
—
—
(5,139)
(132,079)
$ (189,528) $
—
—
—
—
(1,241)
6,910
(3,510)
(5,139)
(132,079)
87,591
731
(1,056)
4,216
287
(1,617)
(5,139)
14,082
99,095
(1,617)
—
—
—
(5,139)
14,082
$
(1,096) $ (180,585) $
See accompanying Notes to Consolidated Financial Statements.
F-6
PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization and Summary of Significant Accounting Policies
PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest”) is an independent oil and gas company headquartered
in Lafayette, Louisiana with exploration offices in The Woodlands, Texas and Tulsa, Oklahoma. It is engaged in the exploration,
development, acquisition and operation of oil and gas properties in Oklahoma and Texas as well as onshore and in the shallow
waters offshore the Gulf Coast Basin.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of PetroQuest and its subsidiaries, PetroQuest Energy, L.L.C.,
PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC (collectively, the "Company"). All intercompany accounts and
transactions have been eliminated. Certain prior period amounts have been reclassified to conform to current year presentation.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States
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. Actual results could differ from those estimates.
Oil and Gas Properties
The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and
development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive
wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and
administrative costs that can be directly identified with acquisition, exploration or development of oil and gas properties.
Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the
properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property
costs. Transactions involving sales of reserves in place, unless significant, are recorded as adjustments to accumulated depreciation,
depletion and amortization with no gain or loss recognized.
Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based
on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development
costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded
from this calculation until the related properties are evaluated, proved reserves are established or the properties are determined to
be impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers.
The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net future cash
flows from proved reserves based on historical first of the month average twelve-month oil, gas and natural gas liquid prices,
including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the
full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The
Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of ASC Topic 410-20
by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and
abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation.
The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the
computation of the present value of estimated future net revenues used in applying the ceiling test.
Cash and Cash Equivalents
The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash
equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial
bank accounts, which result in available funds the next business day.
Accounts Receivable
In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their
respective working interests. As of December 31, 2013 and 2012, the Company had $0.1 million recorded related to an allowance
F-7
for doubtful accounts on its joint interest billing receivable. At December 31, 2012, $9.2 million was recorded as an other receivable
relative to net proceeds from the sale of the Company's non-operated Arkansas assets, which were collected in January 2013.
Other Current Assets
Other current assets at December 31, 2013 and 2012 included $3.1 million and $0.4 million, respectively, related to an
insurance receivable related to operations in our Oklahoma acreage.
Other Property and Equipment
During 2006, the Company acquired a gas gathering system used in the transportation of natural gas. The costs related
to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years. The costs related
to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging from 3-8 years. During
2012, a field office servicing the Company's Oklahoma assets was built and is being depreciated over 39 years.
Other Assets
Other assets at December 31, 2013 and 2012 included $7.4 million and $3.5 million, respectively, related to deferred
financing costs, which are amortized over the life of the related debt. Additionally, other assets includes the long-term portion of
a severance tax receivable from the state of Oklahoma, which is payable over the next 1.5 years.
Other Accrued Liabilities
Other accrued liabilities at December 31, 2013 and 2012 included $6.5 million and $5.7 million, respectively, related to
accrued incentive compensation costs.
Income Taxes
The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred
taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial
reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are
capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment
and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most
other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions
of the Internal Revenue Code which allow capitalization of intangible drilling costs. Other financial and income tax reporting
differences occur primarily as a result of statutory depletion. Deferred tax assets are assessed for realizabilty and a valuation
allowance is established for any portion of the asset for which it is more likely than not will not be realized.
Revenue Recognition
The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the
Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts
to which the Company is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 2013 and
2012 were not significant.
Certain Concentrations
The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify
its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.
The following table identifies customers from whom the Company derived 10% or more of its net oil and gas revenues
during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these
customers would have a significant effect on its business or financial condition.
Shell Trading Co.
Laclede Energy
Unimark, LLC
JP Morgan Ventures Energy
Texon LP
Gary Williams
Year Ended December 31,
2013
2012
2011
35%
14%
14%
(a)
(a)
(a)
30%
17%
(a)
12%
(a)
(a)
18%
20%
(a)
(a)
15%
11%
F-8
(a) Less than 10 percent
Derivative Instruments
Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge
accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair
value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net
of related taxes, to the extent the hedge is effective. If a hedge becomes ineffective because the hedged production does not occur,
or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded
in the income statement as derivative income (expense). The Company does not offset fair value amounts recognized for derivative
instruments. The cash settlements of hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues include additions
related to the net settlement of hedges totaling $0.9 million, $9.1 million and $2.4 million during 2013, 2012 and 2011, respectively.
The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges
is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the
correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the
Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX
prices at which the hedges will be settled. At December 31, 2013, the Company’s derivative instruments were designated as
effective cash flow hedges. See Note 7 for further discussion of the Company’s derivative instruments.
Note 2—Acquisition
On July 3, 2013, the Company acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired
Assets”), for an aggregate cash purchase price of $188.8 million, reflecting an effective date of January 1, 2013 (collectively, the
"Gulf of Mexico Acquisition"). The Acquired Assets included 16 gross wells located on seven platforms.
The aggregate cash purchase price of the Gulf of Mexico Acquisition was financed with the net proceeds from the sale
of $200 million in aggregate principal amount of the Company's 10% Senior Notes due 2017. The Company subsequently registered
the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes"). The New Notes have
terms that, subject to certain exceptions, are substantially identical to the Company's existing $150 million aggregate principal
amount of 10% Senior Notes due 2017. In connection with the transaction, the Company recorded $5 million of deferred financing
costs related to the New Notes and incurred $4.0 million of acquisition-related costs, including $2.6 million related to a bridge
commitment fee, which were recognized as general and administrative expenses.
The Gulf of Mexico Acquisition is accounted for under the purchase method of accounting, which involves determining
the fair value of the assets acquired and liabilities assumed. The fair value of proved and unevaluated oil and gas properties was
estimated using the income approach based on estimated reserve quantities, costs to produce and develop reserves, and forward
prices for oil and gas, which represent Level 2 and Level 3 inputs. Asset retirement obligations were determined in accordance
with applicable accounting standards.
The following table summarizes the acquisition date fair values of the net assets acquired (in thousands):
Oil and gas properties
Unevaluated oil and gas properties
Asset retirement obligations
Net assets acquired
$
$
192,067
12,033
(15,319)
188,781
The following unaudited summary pro forma financial information for the twelve month periods ended December 31,
2013 and 2012 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The
pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place
on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results
reflected in the following unaudited pro forma financial information because of normal production declines, changes in commodity
prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts are presented
in thousands, except per share amounts.
F-9
Revenues
Income (Loss) from Operations
Net Income (Loss) available to common stockholders
Basic Earnings (loss) per Share
Diluted Earnings (loss) per Share
Twelve Months Ended December 31,
2013
2012
$
$
$
215,666
$
19,858
14,399
0.22
0.22
$
$
187,104
(135,406)
(142,181)
(2.28)
(2.28)
Note 3—Convertible Preferred Stock
The Company has 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series
B Preferred Stock”) outstanding.
The following is a summary of certain terms of the Series B Preferred Stock:
Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B
Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited
by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an
authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.
Mandatory conversion. The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically
converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days
within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the
conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.
Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into
3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share
of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a
portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion
of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver
upon conversion (if any) will be based upon a 20 trading day averaging period.
Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on
the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided
by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The
conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered
upon conversion may be adjusted if certain events occur.
F-10
Note 4—Earnings Per Share
A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share
amounts) is as follows:
For the Year Ended December 31, 2013
Net income available to common stockholders
Attributable to participating securities
BASIC EPS
Net income available to common stockholders
Effect of dilutive securities:
Stock options
Attributable to participating securities
DILUTED EPS
For the Year Ended December 31, 2012
BASIC EPS
Net loss available to common stockholders
Effect of dilutive securities:
Stock options
Restricted stock
DILUTED EPS
For the Year Ended December 31, 2011
Net income available to common stockholders
Attributable to participating securities
BASIC EPS
Net income available to common stockholders
Effect of dilutive securities:
Stock options
Attributable to participating securities
DILUTED EPS
Income
(Numerator)
Shares
(Denominator)
Per
Share Amount
$
$
$
$
8,943
(257)
8,686
8,943
—
(256)
8,687
0.14
63,054
—
63,054
$
63,054
154
—
63,208
$
0.14
Loss
(Numerator)
Shares
(Denominator)
Per
Share Amount
(137,218)
62,459
$
(2.20)
$
$
—
—
(137,218)
—
—
62,459
$
Income
(Numerator)
$
$
$
$
5,409
(154)
5,255
5,409
—
(153)
5,256
Shares
(Denominator)
Per
Share Amount
61,937
—
61,937
61,937
388
—
62,325
$
$
(2.20)
0.08
0.08
Common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 5.1 million shares during
2013 and 2011 were not included in the computation of diluted earnings per share because the inclusion would have been anti-
dilutive. Options to purchase 1.2 million and 0.1 million shares of common stock were outstanding during the year ended
December 31, 2013 and 2011, respectively, and were not included in the computation of diluted earnings per share because the
options' exercise prices were in excess of the average market price of the common shares.
An aggregate of 0.9 million shares of common stock representing options to purchase common stock and unvested shares
of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling
5.1 million shares were not included in the computation of diluted earnings per share for the year ended December 31, 2012,
because the inclusion would have been anti-dilutive as a result of the net loss reported for the period.
F-11
Note 5—Share-Based Compensation
Share-based compensation expense is reflected as a component of the Company’s general and administrative expense.
A detail of share-based compensation expense for the periods ended December 31, 2013, 2012 and 2011 is as follows (in thousands):
Year Ended December 31,
2012
2011
2013
Stock options:
Incentive Stock Options
Non-Qualified Stock Options
Restricted stock
Restricted stock units
Share-based compensation
$
$
310
222
3,684
1,611
5,827
$
$
786
660
5,464
277
7,187
$
$
493
703
3,637
—
4,833
During the years ended December 31, 2013, 2012 and 2011, the Company recorded income tax benefits of approximately
$1.8 million, $2.3 million and $1.6 million, respectively, related to share-based compensation expense recognized during those
periods. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in
paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred
and the Company has net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been
recognized for any periods presented.
At December 31, 2013, the Company had $6.8 million of unrecognized compensation cost related to unvested restricted
stock and stock options. This amount will be recognized as compensation expense over a weighted average period of approximately
three years.
Stock Options
Stock options generally vest equally over a three-year period, must be exercised within 10 years of the grant date and
may be granted only to employees, directors and consultants. The exercise price of each option may not be less than 100% of the
fair market value of a share of common stock on the date of grant. Upon a change in control of the Company, all outstanding
options become immediately exercisable.
The Company computes the fair value of its stock options using the Black-Scholes option-pricing model assuming a
stock option forfeiture rate and expected term based on historical activity and expected volatility computed using historical stock
price fluctuations on a weekly basis for a period of time equal to the expected term of the option. The Company recognizes
compensation expense using the accelerated expense attribution method over the vesting period. Periodically, the Company adjusts
compensation expense based on the difference between actual and estimated forfeitures.
The following table outlines the assumptions used in computing the fair value of stock options granted during 2013, 2012
and 2011:
Years Ended December 31,
Dividend yield
Expected volatility
Risk-free rate
Expected term
Forfeiture rate
Stock options granted (1)
Wgtd. avg. grant date fair value per share
Fair value of grants (1)
(1) Prior to applying estimated forfeiture rate
2013
—%
2011
—%
2012
—%
79.6% - 79.8% 79.2% - 79.6% 78.5% - 79.7%
1.1% - 2.2%
0.8% - 1.1%
0.9% - 1.815%
6 years
6 years
6 years
5.0%
5.0%
5.0%
395,642
2.91
1,150,000
$
$
125,487
3.71
465,000
$
$
395,280
5.09
2,011,000
$
$
F-12
The following table details stock option activity during the year ended December 31, 2013:
Outstanding at beginning of year
Granted
Expired/cancelled/forfeited
Exercised
Outstanding at end of year
Options exercisable at end of year
Options expected to vest
Wgtd. Avg.
Remaining
Life
Aggregate
Intrinsic Value
(000’s)
Number of
Options
1,924,941
395,642
(120,090)
(308,000)
1,892,493
Wgtd. Avg.
Exercise Price
5.61
$
4.22
7.22
2.81
5.67
1,317,795
545,963
$
5.99
4.95
4.3 years
9.1 years
5.8 years
$
$
$
360
324
34
The total fair value of stock options that vested during the years ended December 31, 2013, 2012 and 2011 was $0.8
million, $1.7 million and $1.1 million, respectively. The intrinsic value of stock options exercised was immaterial for all periods
presented.
The following table summarizes information regarding stock options outstanding at December 31, 2013:
Range of
Exercise
Price
$2.24—$4.48
$4.48—$6.72
$6.72—$8.96
$8.96—$11.20
Restricted Stock
Options
Outstanding
12/31/2013
684,141
389,320
809,032
10,000
1,892,493
Wgtd. Avg.
Remaining
Contractual Life
5.4 years
5.1 years
6.5 years
2.1 years
5.8 years
Wgtd. Avg.
Exercise
Price
$3.75
$5.64
$7.26
$9.99
$5.67
Options
Exercisable
12/31/2013
316,499
275,997
715,299
10,000
1,317,795
Wgtd. Avg.
Exercise
Price
$3.26
$5.78
$7.22
$9.99
$5.99
The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock
at the date of grant, and compensation expense is recognized assuming a 5% estimated forfeiture rate. Restricted stock granted to
employees prior to 2011 generally vests over a five-year period with one-fourth vesting on each of the first, second, third and fifth
anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant.
Prior to 2013, restricted stock granted to directors generally vested evenly over a three year period. In 2013, restricted stock
granted to directors vests one year from the date of grant, to align with their term on the board. Beginning January 1, 2011,
restricted stock granted to employees generally vests evenly over a three year period. Upon a change in control of the Company,
all outstanding shares of restricted stock will become immediately vested. Compensation expense related to restricted stock is
recognized over the vesting period using the accelerated expense attribution method.
The following table details restricted stock activity during 2013:
Outstanding at beginning of year
Granted
Expired/cancelled/forfeited
Lapse of restrictions
Outstanding at December 31, 2013
Number of
Shares
Wgtd. Avg.
Fair Value per
Share
1,805,829
1,078,000
(186,926)
(770,452)
1,926,451
$
$
6.28
4.18
5.85
6.95
4.88
The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2013, 2012
and 2011 was $4.18, $5.24 and $7.54, respectively, per share. The total fair value of restricted stock that vested during the years
ended December 31, 2013, 2012 and 2011 was $5.4 million, $4.7 million and $5.6 million, respectively. At December 31, 2013,
the weighted average remaining life of restricted stock outstanding was two years and the intrinsic value of restricted stock
outstanding, using the closing stock price on December 31, 2013, was $8.3 million.
F-13
Restricted Stock Units
The Company granted restricted stock units ("RSUs") to employees during 2013 and 2012. The RSUs vest in one-third
increments on each of the first, second and third anniversaries of the date of grant. Cash payment will be made to employees on
each vesting date based upon the Company's closing stock price on that date. Upon change in control of the Company, all of the
RSUs will immediately vest. Compensation expense is recognized on a straight line basis over the vesting period assuming a 5%
estimated forfeiture rate. The Company computes the fair value of the RSUs using the closing price of the Company's stock for
purposes of determining the amount of the liability at the end of each period. During 2013 the Company paid $1.6 million for
units that vested during the period. As of December 31, 2013, the Company had a liability for RSUs outstanding and expected to
vest in the amount of $0.3 million and an intrinsic value on all RSUs outstanding of $5.5 million.
Outstanding at beginning of year
Granted
Expired/Cancelled/Forfeited
Vested/Paid
Outstanding at December 31, 2013
Number of
Shares
1,096,158
703,777
(141,378)
(385,140)
1,273,417
Note 6—Asset Retirement Obligation
The Company accounts for asset retirement obligations in accordance with ASC Topic 410-20, which requires recording
the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Asset retirement
obligations associated with long-lived assets included within the scope of ASC Topic 410-20 are those for which there is a legal
obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of
promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has
acquired and constructed.
The following table describes all changes to the Company’s asset retirement obligation liability (in thousands):
Asset retirement obligation, beginning of period
Liabilities assumed
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows
Asset retirement obligation, end of period
Less: current portion of asset retirement obligation
Long-term asset retirement obligation
Year Ended December 31,
2013
2012
$
$
27,260
15,319
498
(3,335)
1,753
7,041
48,536
(3,113)
45,423
$
$
30,427
—
892
(2,627)
2,078
(3,510)
27,260
(2,351)
24,909
Note 7—Derivative Instruments
The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through
commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity
derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment
are recorded in other comprehensive income (loss) until the hedged oil, natural gas or natural gas liquids (Ngl) quantities are
produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify
for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative
income (expense). At December 31, 2013, the Company designated all of its derivative instruments as effective cash flow hedges.
At December 31, 2012, the Company designated all derivative instruments except its three-way collar as effective cash flow
hedges.
F-14
Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $1,098,000, $6,846,000 and
$2,609,000, Ngl hedges of $61,000, $722,000 and zero, and oil hedges of ($232,000), $1,529,000 and ($192,000), for the years
ended December 31, 2013, 2012 and 2011, respectively.
As of December 31, 2013, the Company had entered into the following gas hedge contracts:
Production Period
Natural Gas:
2014
Crude Oil:
January - June 2014
2014
2014
LLS - Louisiana Light Sweet
WTI - West Texas Intermediate
Instrument
Type
Daily Volumes
Weighted
Average Price
Swap
40,000 Mmbtu
Swap (LLS)
Swap (LLS)
Swap (WTI)
450 Bbls
400 Bbls
350 Bbls
$4.12
$100.58
$101.15
$93.26
At December 31, 2013, the Company had recognized a net liability of approximately $1.1 million related to the estimated
fair value of these derivative instruments. Based on estimated future commodity prices as of December 31, 2013, the Company
would realize a $0.7 million loss, net of taxes, during the next 12 months. These losses are expected to be reclassified to oil and
gas sales based on the schedule of oil and gas volumes stipulated in the derivative contracts.
During January 2014, the Company entered into the following additional hedge contract accounted for as a cash flow
hedge:
Production Period
Natural Gas:
March - December 2014
Instrument
Type
Daily Volumes
Weighted
Average Price
Swap
5,000 Mmbtu
$4.285
Derivatives designated as hedging instruments:
The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial
statements (in thousands):
Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2013 and December 31, 2012:
Period
December 31, 2013
December 31, 2013
December 31, 2012
Commodity Derivatives
Balance Sheet
Location
Fair Value
Derivative asset
Derivative liability
Derivative asset
$
$
$
521
(1,617)
830
F-15
Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the twelve months ended December 31, 2013, 2012
and 2011:
Instrument
Commodity Derivatives at December 31, 2013
Commodity Derivatives at December 31, 2012
Commodity Derivatives at December 31, 2011
Derivatives not designated as hedging instruments:
Amount of Gain (Loss)
Recognized in Other
Comprehensive Income
(1,617)
$
(3,510)
$
5,120
$
Location of
Gain Reclassified
into Income
Oil and gas sales
Oil and gas sales
Oil and gas sales
$
$
$
Amount of Gain
Reclassified into
Income
994
9,097
2,417
The Company’s three-way collar contract for 2013 gas production was not designated as an effective cash flow hedge
and therefore both realized and unrealized (mark-to-market) gains or losses on this derivative were recorded as derivative expense
(income) in the statement of operations. The following tables reflect the fair value of this contract in the consolidated financial
statements (in thousands):
Effect of Non-designated Derivative Instrument on the Consolidated Balance Sheet at December 31, 2012:
Period
December 31, 2012
Commodity Derivatives
Balance Sheet Location
Fair Value
Derivative liability
$
(233)
Effect of Non-designated Derivative Instrument on the Consolidated Statement of Operations for the twelve months ended
December 31, 2013, 2012 and 2011:
Instrument
Commodity Derivatives at December 31, 2013
Commodity Derivatives at December 31, 2012
Commodity Derivatives at December 31, 2011
$
$
$
Amount of Gain (Loss)
Recognized in Derivative
Income (Expense)
233
(233)
—
Note 8 - Fair Value Measurements
ASC Topic 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date and establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad
levels:
• Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the
highest priority;
• Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset
or liability;
• Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant
to the fair value measurement and are less observable and thus have the lowest priority.
The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company's
derivative instruments at December 31, 2013 were in the form of swaps based on NYMEX pricing for oil and natural gas. The
fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated
inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an
estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative
liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.
F-16
The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis
as of December 31, 2013 and December 31, 2012 (in thousands):
Instrument
Commodity Derivatives:
At December 31, 2013
At December 31, 2012
Quoted Prices
in Active
Markets (Level 1)
Fair Value Measurements Using
Significant Other
Observable
Inputs (Level 2)
Significant
Unobservable
Inputs (Level 3)
$
$
— $
— $
(1,096) $
$
597
—
—
The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at
December 31, 2013 and 2012. As of December 31, 2013, the fair value of the Company's $350 million 10% Senior Notes due
2017 (the "Notes") was approximately $364.0 million. As of December 31, 2012, the fair value of the Company's $150 million
in principal amount of Notes was approximately $155.3 million. The fair value of the Notes was determined based upon a market
quote provided by an independent broker, which represents a Level 2 input.
Note 9—Long-Term Debt
On August 19, 2010, PetroQuest issued $150 million in principal amount of Notes (the "Existing Notes") in a public
offering. On July 3, 2013, PetroQuest issued an additional $200 million in aggregate principal amount of Notes. PetroQuest
subsequently registered the Notes in an exchange offer completed in September 2013 (the "New Notes" and together with the
Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of their face value plus accrued interest from
March 1, 2013. The New Notes have terms that, subject to certain exceptions, are substantially identical to the Existing Notes.
The net proceeds from the offering were used to finance the $188.8 million aggregate cash purchase price of the Gulf of Mexico
Acquisition, which also closed on July 3, 2013. The Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary
guarantors are 100% owned by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no
independent assets or operations and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities
and Exchange Commission.
The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend
payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At December 31, 2013,
$11.7 million had been accrued in connection with the March 1, 2014 interest payment and the Company was in compliance with
all of the covenants contained in the Notes.
The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit
Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A. and IberiaBank. The Credit Agreement
provides the Borrower with a $300 million revolving credit facility that permits borrowings based on the commitments of the
lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also
allows the Borrower to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3,
2016. As of December 31, 2013, the Borrower had $75.0 million of borrowings outstanding under (and no letters of credit issued
pursuant to) the Credit Agreement.
The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Borrower's
oil and gas properties as of January 1 and July 1 of each year. On July 3, 2013 the borrowing base was increased from $150 million
to $200 million (subject to the aggregate commitments of the lenders then in effect). As of December 31, 2013, the aggregate
commitments of the lenders is $150 million and can be increased to up to $300 million by either adding new lenders or increasing
the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur
by March 31, 2014. The Borrower or the lenders may request two additional borrowing base redeterminations each year. Each
time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing
base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased,
or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same
or is reduced.
The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries,
including a lien on all equipment and at least 80% of the aggregate total value of the Borrower's oil and gas properties. Outstanding
balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of
0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale
of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime
rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of
alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month
F-17
maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London
interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London
interbank market for one, two, three or six months (as selected by the Borrower) are quoted, as adjusted for statutory reserve
requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to
the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Borrower pays
commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.
The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement,
including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.5 to 1.0, and a minimum
ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The
Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions,
investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of
receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances
and swap agreements. However, the Credit Agreement permits the Borrower to repurchase up to $10 million of the Company’s
common stock during the term of the Credit Agreement, as long as after giving effect to such repurchase the Borrower’s Liquidity
(as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of December 31, 2013, the
Borrower was in compliance with all of the covenants contained in the Credit Agreement.
Note 10—Related Party Transactions
Two of the Company’s senior officers, Charles T. Goodson and Stephen H. Green, or their affiliates, are working interest
owners and overriding royalty interest owners and E. Wayne Nordberg and William W. Rucks, IV, two of the Company’s directors,
are working interest owners in certain properties operated by the Company or in which the Company also holds a working interest.
As working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their
proportionate share of revenues in the normal course of business. As overriding royalty interest owners, they are entitled to receive
their proportionate share of revenues in the normal course of business.
During 2013, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs,
were disbursed to Messrs. Goodson and Green, or their affiliates, in the amounts of $92,000 and $269,000, respectively, and with
respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $200. During 2012, in their capacities as
working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green
and Nordberg, or their affiliates, in the amounts of $104,000, $387,000 and $100, respectively. During 2011, in their capacities
as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson and
Green, or their affiliates, in the amounts of $293,000, $546,000, respectively, and with respect to Mr. Nordberg, costs billed
exceeded revenues in the amount of $9. No such disbursements were made to Mr. Rucks during any reported period. With respect
to Mr. Goodson, gross revenues attributable to interests, properties or participation rights held by him prior to joining the Company
as an officer and director on September 1, 1998 represent all of the gross revenue received by him during these periods.
In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their
respective working interests. At December 31, 2013, the Company’s joint interest billing receivable included approximately
$19,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents less than
1% of the Company’s total joint interest billing receivable at December 31, 2013.
Periodically, the Company charters private aircraft for business purposes. During 2012 and 2011, the Company paid
approximately $16,900 and $128,200, respectively, to a third party operator in connection with the Company’s use of flight hours
owned by Charles T. Goodson through a fractional ownership arrangement with the third party operator. These amounts represent
the cost of the hours purchased by Mr. Goodson. No such amounts were incurred during 2013. The Company’s use of flight hours
purchased by Mr. Goodson was pre-approved by the Company’s Audit Committee and there is no agreement or obligation by or
on behalf of the Company to utilize this aircraft arrangement.
Note 11—Ceiling Test Write-downs
As a result of lower natural gas prices and their negative impact on certain of the Company’s longer-lived estimated
proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of $137.1 million and $18.9
million during 2012 and 2011, respectively. No such write-down occurred during 2013. At December 31, 2012, the prices used
in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges
in place at that date, averaged $2.21 per Mcf of natural gas, $102.81 per barrel of oil and $6.07 per Mcfe of Ngl. The Company’s
cash flow hedges in place decreased the ceiling test write-down by approximately $2.2 million and $3.9 million during 2012 and
2011, respectively.
F-18
Note 12—Other Comprehensive Income
The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year
ended December 31, 2013 (in thousands):
Gains and Losses
on Cash Flow
Hedges
Change in
Valuation
Allowance
Total
Balance as of December 31, 2012
Other comprehensive loss before
reclassifications
Amounts reclassified from accumulated
other comprehensive income
Net other comprehensive loss
Balance as of December 31, 2013
$
$
521
$
(585)
(624)
(1,209)
(688) $
— $
(408)
—
(408)
(408) $
521
(993)
(624)
(1,617)
(1,096)
Refer to Note 7 - Derivative Instruments for additional details about the effect of the above reclassifications.
Note 13—Investment in Oil and Gas Properties—Unaudited
The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are
located onshore and offshore in the continental United States:
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(amounts in thousands)
Acquisition costs:
Proved (1)
Unproved (1)
Divestitures—unproved (2)
Exploration costs:
Proved
Unproved
Development costs
Capitalized general and administrative and interest costs
For the Year-Ended December 31,
2013
2012
2011
$ 177,880
$
352
$
2,720
35,008
(487)
15,677
(8,889)
43,207
(14,461)
34,344
20,112
41,328
19,911
72,361
18,033
18,740
18,961
92,466
5,919
34,400
18,210
Total costs incurred
$ 328,096
$ 135,235
$ 182,461
Accumulated depreciation, depletion and
amortization (DD&A)
Balance, beginning of year
Provision for DD&A
Ceiling test writedown
Sale of proved properties and other (3)
Balance, end of year
DD&A per Mcfe
For the Year-Ended December 31,
2013
2012
2011
(1,472,244) $
(69,357)
—
(11,443)
(1,553,044) $
(1,265,603) $
(59,496)
(137,100)
(10,045)
(1,472,244) $
(1,175,553)
(57,143)
(18,907)
(14,000)
(1,265,603)
1.82
$
1.75
$
1.89
$
$
$
F-19
(1) During 2013, the Company closed on the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8
million (see Note 2 - Acquisition). Additionally, the Company acquired 13,500 net unevaluated acres in Oklahoma targeting
the Woodford Shale.
(2) During 2012, the Company sold an additional portion of its Mississippian Lime acreage for $6.1 million. During 2011,
the Company sold a portion of its unproved Mississippian Lime acreage for $14.5 million.
(3) During 2013, the Company sold 50% of its saltwater disposal systems and related surface assets in the Woodford for net
proceeds of approximately $10.4 million. and its non-operated Wyoming assets for a cash purchase price of $1.0 million.
During 2012, the Company sold its non-operated Arkansas assets for a net cash purchase price of $8.5 million. During
2011, the Company received an additional $14 million payment associated with the achievement of certain production
metrics stipulated under the joint development agreement.
At December 31, 2013 and 2012, unevaluated oil and gas properties totaled $98.4 million and $71.7 million, respectively,
and were not subject to depletion. Unevaluated costs at December 31, 2013 included $11.3 million of costs related to 19 exploratory
wells in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2014 upon the
completion of drilling. At December 31, 2012, unevaluated costs included $12.7 million related to 17 exploratory wells in progress.
All of these costs were transferred to evaluated oil and gas properties during 2013. The Company capitalized $6.6 million, $7.0
million and $7.0 million of interest during 2013, 2012 and 2011, respectively. Of the total unevaluated oil and gas property costs
of $98.4 million at December 31, 2013, $50.3 million, or 51%, was incurred in 2013, $12.1 million, or 12%, was incurred in 2012
and $36.0 million, or 37%, was incurred in prior years. The Company expects that the majority of the unevaluated costs at
December 31, 2013 will be evaluated within the next three years, including $34.4 million that the Company expects to be evaluated
during 2014.
Note 14—Income Taxes
The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected
to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of
the ceiling test write-downs recognized during 2011 and 2012, the Company incurred a cumulative three-year loss. Because of
the impact the cumulative loss had on the determination of the recoverability of deferred tax assets through future earnings, the
Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities.
Accordingly, the Company established a valuation allowance of $45.5 million as of December 31, 2013.
An analysis of the Company’s deferred taxes follows (amounts in thousands):
December 31,
2013
2012
2011
Net operating loss carryforwards
$
21,810
$
16,641
$
Percentage depletion carryforward
Alternative minimum tax credits
Contributions carryforward and other
Temporary differences:
Oil and gas properties
Asset retirement obligation
Derivatives
Share-based compensation
Valuation allowance
Deferred tax liability
8,645
784
189
(7,248)
18,056
408
2,887
(45,531)
7,317
784
156
12,575
10,141
(222)
3,474
(50,866)
$
— $
— $
2,409
6,103
784
130
(21,860)
11,319
(2,388)
2,952
—
(551)
At December 31, 2013, the Company had approximately $70.7 million of operating loss carryforwards, of which $12.1
million relates to excess tax benefits with respect to share-based compensation that have not been recognized in the financial
statements. If not utilized, approximately $8.7 million of such carryforwards would expire in 2025 and the remainder would expire
by the year 2033. The Company has available for tax reporting purposes $24.7 million in statutory depletion deductions that may
be carried forward indefinitely.
F-20
Income tax expense (benefit) for each of the years ended December 31, 2013, 2012 and 2011 was different than the
amount computed using the Federal statutory rate (35%) for the following reasons (amounts in thousands):
For the Year Ended December 31,
2013
2012
2011
Amount computed using the statutory rate
$
5,041
$
(45,655)
$
3,058
Increase (reduction) in taxes resulting from:
State & local taxes
Percentage depletion carryforward
Allowance for alternative minimum tax
Non-deductible stock option expense (1)
Share-based compensation (2)
Other
Change in valuation allowance
Income tax expense (benefit)
$
317
(1,323)
—
115
780
1,132
(5,742)
320
(2,870)
(1,309)
—
292
9
303
50,866
$
1,636
$
192
(2,507)
8
183
346
(300)
(2,790)
(1,810)
(1) Relates to compensation expense recognized on the vesting of Incentive Stock Options.
(2) Relates to the write-off of deferred tax assets associated with share based compensation that will not be recognized for tax
purposes.
Note 15—Commitments and Contingencies
The Company is a party to ongoing litigation in the normal course of business. While the outcome of lawsuits or other
proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition,
results of operations and cash flows, if any, will not be material. At December 31, 2010, the Company had accrued $2.3 million
in connection with estimated liabilities related to certain legal matters. All of these matters were settled during 2011, which resulted
in an additional charge of $1.4 million included in other expense for the year ended December 31, 2011.
Lease Commitments
The Company has operating leases for office space and equipment, which expire on various dates through 2018. Future
minimum lease commitments as of December 31, 2013 under these operating leases are as follows (in thousands):
2014
2015
2016
2017
2018
Thereafter
$
$
1,384
1,452
1,414
1,312
411
2,032
8,005
Total rent expense under operating leases was approximately $1.4 million, $1.4 million and $1.3 million in 2013, 2012
and 2011, respectively.
Note 16—Oil and Gas Reserve Information—Unaudited
The Company’s net proved oil and gas reserves at December 31, 2013 have been estimated by independent petroleum
engineers in accordance with guidelines established by the SEC using a historical 12-month average pricing assumption.
The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, 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 renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are
numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and
timing of development expenditures. The following reserve data represents estimates only and should not be construed as being
F-21
exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties
or the cost that would be incurred to obtain equivalent reserves.
During 2013, the Company’s estimated proved reserves increased by 32%. This increase was primarily due to the Gulf
of Mexico Acquisition, the success of the Company's drilling programs and approximately 33 Bcfe of PUD reserves added as a
result of the increase in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves.
In total, the Company added approximately 63 Bcfe of proved reserves in Oklahoma, 41 Bcfe in the Gulf Coast and 6 Bcfe in
Texas. Overall, the Company had a 88% drilling success rate during 2013 on 40 gross wells drilled.
F-22
The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil
(including condensate), gas and natural gas liquid reserves, all located onshore and offshore the continental United States:
Proved reserves as of December 31, 2010
Revisions of previous estimates
Extensions, discoveries and other additions
Purchase of producing properties
Production
Proved reserves as of December 31, 2011
Revisions of previous estimates
Extensions, discoveries and other additions
Sale of reserves in place
Production
Proved reserves as of December 31, 2012
Revisions of previous estimates
Extensions, discoveries and other additions
Purchase of producing properties
Sale of reserves in place
Production
Proved reserves as of December 31, 2013
Proved developed reserves
As of December 31, 2011
Oil
in
MBbls
NGL
in
MMcfe
Natural Gas
in
MMcf
Total
Reserves
in MMcfe
1,623
(294)
595
43
(572)
1,395
215
647
(81)
(521)
1,655
(123)
434
1,833
(34)
(681)
3,084
8,373
308
8,627
91
(2,288)
15,111
(958)
14,572
—
(3,365)
25,360
520
6,099
1,915
—
(4,754)
29,140
174,566
8,418
82,113
1,292
(24,463)
241,926
(52,076)
46,390
(15,806)
(27,466)
192,968
37,738
30,429
22,274
(15)
(29,226)
254,168
192,677
6,962
94,310
1,641
(30,183)
265,407
(51,744)
64,844
(16,292)
(33,957)
228,258
37,518
39,132
35,187
(218)
(38,066)
301,811
1,160
11,071
143,441
161,472
As of December 31, 2012
1,225
20,608
140,307
168,265
As of December 31, 2013
2,709
23,173
163,728
203,152
Proved undeveloped reserves
As of December 31, 2011
As of December 31, 2012
As of December 31, 2013
235
430
375
4,040
98,485
103,935
4,752
52,661
59,993
5,967
90,440
98,659
F-23
The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved
oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are
based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a
10% annual discount rate.
Standardized Measure
Future cash flows
Future production costs
Future development costs
Future income taxes
Future net cash flows
10% annual discount
$
Standardized measure of discounted future net cash flows $
Changes in Standardized Measure
Standardized measure at beginning of year
December 31,
2013
2012
2011
1,265,663
(301,710)
(193,985)
(40,072)
729,896
(276,014)
453,882
$
$
748,914
(220,750)
(121,346)
(10,205)
396,613
(164,218)
232,395
$
$
1,080,392
(264,219)
(180,846)
(86,612)
548,715
(244,834)
303,881
Year Ended December 31,
2013
2012
2011
$
232,395
$
303,881
$
236,375
Sales and transfers of oil and gas produced, net of production costs
Changes in price, net of future production costs
(134,184)
57,293
Extensions and discoveries, net of future production and development costs
70,181
(92,562)
(138,842)
104,066
(116,398)
(10,219)
178,901
Changes in estimated future development costs, net of development costs
incurred during this period
Revisions of quantity estimates
Accretion of discount
Net change in income taxes
Purchase of reserves in place
Sale of reserves in place
Changes in production rates (timing) and other
Net increase (decrease) in standardized measure
(24,327)
57,468
23,927
(14,061)
191,964
(411)
(6,363)
221,487
Standardized measure at end of year
$
453,882
$
69,499
(56,352)
34,137
30,617
—
(8,186)
(13,863)
(71,486)
232,395
915
11,236
25,565
(18,215)
4,805
—
(9,084)
67,506
$
303,881
The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure
were:
Oil, $/Bbl
Ngls, $/Mcfe
Natural Gas, $/Mcf
2013
2012
2011
$106.19
$102.81
5.10
3.11
6.07
2.20
$101.42
8.62
3.34
F-24
Note 17 - Summarized Quarterly Financial Information - Unaudited
Summarized quarterly financial information is as follows (amounts in thousands except per share data):
2013:
Revenues
Income from operations
Income available to common stockholders
Earnings per share:
Basic
Diluted
2012:
Revenues
Loss from operations (1)
Loss available to common stockholders (1)
Earnings per share:
Basic
Diluted
Quarter Ended
March 31
June 30
September 30 December 31
$
36,009 $
38,102 $
55,587 $
53,172
4,236
2,607
4,109
3,662
1,687
383
0.04 $
0.04 $
0.06 $
0.06 $
0.01 $
0.01 $
4,370
2,291
0.04
0.04
36,041 $
(18,314)
(18,608)
33,413 $
(52,183)
(54,520)
33,951 $
(35,919)
(38,639)
38,186
(24,027)
(25,451)
(0.30) $
(0.30) $
(0.87) $
(0.87) $
(0.62) $
(0.62) $
(0.41)
(0.41)
$
$
$
$
$
(1) Loss from operations and net loss available to common stockholders reported during the three months ended March 31,
June 30, September 30 and December 31, 2012 included ceiling test write-downs of $20.1 million, $53.5 million, $35.4 million
and $28.1 million, respectively.
F-25
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
(1) Registration Statement (Form S-3 No. 333-190645) of PetroQuest Energy, Inc. and the related Prospectus, and
(2) Registration Statement (Form S-3 No. 333-124746) of PetroQuest Energy, Inc. and the related Prospectus, and
(3) Registration Statement (Form S-3 No. 333-42520) of PetroQuest Energy, Inc. and the related Prospectus, and
(4) Registration Statement (Form S-3 No. 333-89961) of PetroQuest Energy, Inc. and the related Prospectus, and
(5) Registration Statement (Form S-8 No. 333-188731) pertaining to the PetroQuest Energy, Inc. 2013 Incentive
Plan, and
(6) Registration Statement (Form S-8 No. 333-184926) pertaining to the PetroQuest Energy, Inc. 2012 Employee
Stock Purchase Plan, and
(7) Registration Statement (Form S-8 No. 333-174260) pertaining to the PetroQuest Energy, Inc. 1998 Amended
and Restated Incentive Plan, and
(8) Registration Statement (Form S-8 No. 333-151296) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan, and
(9) Registration Statement (Form S-8 No. 333-134161) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan, and
(10) Registration Statement (Form S-8 No. 333-102758) pertaining to the PetroQuest Energy, Inc. 1998 Amended
and Restated Incentive Plan, and
(11) Registration Statement (Form S-8 No. 333-88846) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan, and
(12) Registration Statement (Form S-8 No. 333-67578) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan, and
(13) Registration Statement (Form S-8 No. 333-52700) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan, and
(14) Registration Statement (Form S-8 No. 333-65401) pertaining to the PetroQuest Energy, Inc. 1998 Amended and
Restated Incentive Plan;
of our reports dated March 5, 2014, with respect to the consolidated financial statements of PetroQuest Energy, Inc.
and the effectiveness of internal control over financial reporting of PetroQuest Energy, Inc. included in this Annual
Report (Form 10-K) of PetroQuest Energy, Inc. for the year ended December 31, 2013.
New Orleans, Louisiana
March 5, 2014
/s/ Ernst & Young LLP
TBPE REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA SUITE 4600
HOUSTON, TEXAS 77002-5294
FAX (713) 651-0849
TELEPHONE (713) 651-9191
EXHIBIT 23.2
CONSENT OF RYDER SCOTT COMPANY, L.P.
We hereby consent to (i) the inclusion of our reserve report relating to certain estimated quantities
of the proved reserves of oil and gas, future net income and discounted future net income, effective
December 31, 2013 of PetroQuest Energy, Inc. (the “Company”) in this Annual Report on Form 10-K
prepared by the Company for the year ending December 31, 2013, filed as Exhibit 99.1 of the Form 10-
K, and (ii) the incorporation by reference in this Annual Report on Form 10-K prepared by the Company
for the year ending December 31, 2013, and to the incorporation by reference thereof into the Company’s
previously filed Registration Statements on Form S-3 (File Nos. 333-190645, 333-124746, 333-42520 and
333-89961) and Form S-8 (File Nos. 333-188731, 333-184926, 333-174260, 333-151296, 333-134161,
333-102758, 333-88846, 333-67578, 333-52700 and 333-65401), of information contained in our report
relating to certain estimated quantities of the Company’s proved reserves of oil and gas, future net income
and discounted future net income, effective December 31, 2013. We further consent to references to our
firm under the headings “Business and Properties - Oil and Gas Reserves” and “Risk Factors,” and included
in or made a part of the Annual Report on Form 10-K prepared by the Company for the year ended
December 31, 2013.
We further wish to advise that we are not employed on a contingent basis and that at the time of
the preparation of our report, as well as at present, neither Ryder Scott Company, L.P. nor any of its
employees had, or now has, a substantial interest in PetroQuest Energy, Inc. or any of its subsidiaries,
as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.
/s/ RYDER SCOTT COMPANY, L.P.
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
Houston, Texas
March 5, 2014
SUITE 600, 1015 4TH STREET, S.W.
621 17TH STREET, SUITE 1550
CALGARY, ALBERTA T2R 1J4
DENVER, COLORADO 80293-1501
TEL (403) 262-2799
TEL (303) 623-9147
FAX (403) 262-2790
FAX (303) 623-4258
I, Charles T. Goodson, certify that:
EXHIBIT 31.1
1.
2.
3.
4.
I have reviewed this Form 10-K of PetroQuest Energy, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to
the period covered by this report;
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods presented
in this report;
The registrant's other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15
(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being
prepared;
(b) Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based on such
evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial
reporting that occurred during the registrant's most recent fiscal quarter (the registrant's
fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal control over financial
reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant's auditors and the
Exhibit 31.1
audit committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect
the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrant's internal control over financial reporting.
_/s/ Charles T. Goodson___
Charles T. Goodson
Chief Executive Officer
March 5, 2014
Exhibit 31.1
2
I, J. Bond Clement, certify that:
EXHIBIT 31.2
1.
2.
3.
4.
I have reviewed this Form 10-K of PetroQuest Energy, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to
the period covered by this report;
Based on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the periods presented
in this report;
The registrant's other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15
(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being
prepared;
(b) Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based on such
evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial
reporting that occurred during the registrant's most recent fiscal quarter (the registrant's
fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal control over financial
reporting; and
5.
The registrant's other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant's auditors and the
Exhibit 31.2
audit committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect
the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrant's internal control over financial reporting.
/s/ J. Bond Clement
J. Bond Clement
Chief Financial Officer
March 5, 2014
Exhibit 31.2
2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.1
In connection with the Annual Report of PetroQuest Energy, Inc. (the “Company”) on Form
10-K for the year ending December 31, 2013 (the “Report”), as filed with the Securities and Exchange
Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company,
certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of
2002, that:
1.
The Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2.
The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company.
/s/Charles T. Goodson
Charles T. Goodson
Chief Executive Officer
March 5, 2014
A signed original of this written statement required by Section 906 has been provided to the Company
and will be retained by the Company and furnished to the Securities and Exchange Commission or
its staff upon request.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.2
In connection with the Annual Report of PetroQuest Energy, Inc. (the “Company”) on Form
10-K for the year ending December 31, 2013 (the “Report”), as filed with the Securities and Exchange
Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify,
pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
1.
The Report fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
2.
The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company.
/s/ J. Bond Clement
J. Bond Clement
Chief Financial Officer
March 5, 2014
A signed original of this written statement required by Section 906 has been provided to the Company
and will be retained by the Company and furnished to the Securities and Exchange Commission or
its staff upon request.
[THIS PAGE INTENTIONALLY LEFT BLANK]
Corporate Information
Board of Directors
Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President
W.J. Gordon III *#^
Vice President of Strategic Planning
Franciscan Missionaries of Our Lady Health System
Michael L. Finch *#^
Private Investments
Charles F. Mitchell II, M.D. *#^
Physician, Private Investments
E. Wayne Nordberg *#^
Hollow Brook Associates, LLC
William W. Rucks, IV *#^
Private Investments
* Member of the Compensation Committee
# Member of the Audit Committee
^ Member of the Nominating and
Corporate Governance Committee
Senior Management
Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President
W. Todd Zehnder
Chief Operating Officer
Edward E. Abels, Jr.
Executive Vice President, General Counsel,
and Corporate Secretary
J. Bond Clement
Executive Vice President
Chief Financial Officer, and Treasurer
Art M. Mixon
Executive Vice President
Operations and Production
Tracy Price
Executive Vice President
Business Development & Land
Stephen H. Green
Senior Vice President
Exploration
Mark K. Castell
Vice President - Oklahoma Assets
Edgar A. Anderson
Vice President - ArkLaTex
Corporate Address
PetroQuest Energy, Inc.
400 East Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
Telephone: (337) 232-7028
Fax: (337) 232-0044
Web: www.petroquest.com
Exploration Offices
1800 Hughes Landing Blvd., Suite 200
The Woodlands, Texas 77380
Telephone: (281) 465-3900
Fax: (281) 465-3999
1717 S. Boulder, Suite 201
Tulsa, Oklahoma 74119
Telephone: (918) 582-2770
Fax: (918) 582-2778
Transfer Agent and Registrar
American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
Telephone: (718) 921-8145
Independent Auditors
Ernst & Young LLP
New Orleans, Louisiana 70170
Legal Counsel
Porter & Hedges, LLP
Houston, Texas 77002
Onebane Law Firm
Lafayette, Louisiana 70502
Annual Meeting
The Company’s Annual Meeting of Stockholders
will be held at 9:00 A.M. CDT on May 14, 2014, at the
City Club at River Ranch at 221 Elysian Fields Drive,
Lafayette, LA, 70508.
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.petroquest.com.
Common Stock Listing
Listed on NYSE as PQ
P E T R O Q U E S T . C O M