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| 8-K - 8-K - PETROQUEST ENERGY INC | jan2017presentation8k.htm |
January 2017
Forward-Looking Statements
2
This presentation contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this presentation are forward-looking statements.
Although PetroQuest believes that the expectations reflected in these forward-looking statements are reasonable, these statements are based upon assumptions
and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, our
ability to successfully close the previously disclosed commitment for a four-year multi-draw term loan facility or receive any proceeds from draws thereunder; the
sufficiency of our current liquidity; the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014; our indebtedness and the
significant amount of cash required to service our indebtedness; our ability to improve our liquidity position and refinance or restructure our indebtedness, including
our 2017 Notes and 2021 2L Notes; the potential need to sell assets or seek bankruptcy protection; our estimate of the sufficiency of our existing capital sources,
including availability under our bank credit facility and the result of any borrowing base redetermination; our ability to post additional collateral to satisfy our
offshore decommissioning obligations; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market;
ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; our ability to raise additional capital to fund cash
requirements for future operations; limits on our growth and our ability to finance our operations, fund our capital needs; our ability to find, develop and produce oil
and natural gas reserves that are economically recoverable and to replace reserves and sustain production; approximately 50% of our production being exposed to
the additional risk of severe weather, including hurricanes, tropical storms and flooding, and natural disasters; losses and liabilities from uninsured or underinsured
drilling and operating activities; changes in laws and governmental regulations as they relate to our operations; the operating hazards attendant to the oil and gas
business; the volatility of our stock price; and our ability to meet the continued listing standards of the New York Stock Exchange with respect to our common stock
or to cure any deficiency with respect thereto. In particular, careful consideration should be given to cautionary statements made in the various reports the
Company has filed with the SEC. The Company undertakes no duty to update or revise these forward-looking statements. In particular, careful consideration should
be given to cautionary statements made in the various reports PetroQuest has filed with the Securities and Exchange Commission. PetroQuest undertakes no duty to
update or revise these forward-looking statements.
Prior to 2010, the Securities and Exchange Commission generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company
has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating
conditions. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected not to disclose
our probable and possible reserves in our filings with the SEC. We use the terms “reserve inventory,” “gross unrisked reserves,” “EUR,” “inventory”, “unrisked
resource potential”, 3P reserves or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable through additional
drilling or recovery techniques that the SEC’s guidelines prohibit us from including in filings with the SEC. Estimates of reserve inventory, gross unrisked reserves
EUR, inventory, unrisked 3P reserves do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or
technically recoverable, a significant recovery factor would be applied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these
estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized
by the Company. The methodology for estimating unrisked inventory, gross unrisked reserves, EUR, or unrisked resource potential or 3P reserves may also be
different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC’s guidelines for estimating probable and
possible reserves.
Our Properties
3
Gulf Coast Mid-Con Woodford ShaleEast Texas Cotton Valley
• ~52,000 gross acres (~28,000 net acres)
• 3Q16 production: 22.5 MMcfe/d
• Recently consummated JV program
• ~$12MM in cash for 1,200 acres
($10K/acre) without selling any production
• PQ pays 69% for 75% WI enhancing
economics
• 47 well program: 8-10 wells for 2017
• 3Q16 production: 32.9 MMcfe/d
• Recently shut-in Thunder Bayou and
recompletion expected to commence
in January – expected to increase
production to 50,000 – 70,000 Mcfe/d
East Texas
Gulf Coast
Mid-Con
2015 Reserves (1)
159 Bcfe
East Texas
Gulf Coast
Mid-Con
3Q16 Production
57 Mmcfe/d
• Sold majority of assets
• $298 MM of gross proceeds
(1) Excludes Oklahoma reserves sold in 2016
3Q16 Production Mix
70% Gas
16% NGL
14% Oil
Industry Activity - Cotton Valley Trend
4
Hutchinson 9: 14.9 MMcfe/d
EGP 63: 12.6 MMcfe/d
Killen 13: 13.1MMcfe/d
Wright 13: 30.3 MMcfe/d
Werner 29: 26.7 MMcfe/d
Colvin Estate 28: 26.6 MMcfe/d
Berry 24H: 11.1 MMcfe/d
Breffeilh: 11.1 MMcfe/d
Walton 23H: 10.6 MMcfe/d
PQ#13: 12.3 MMcfe/d
PQ#14: 13.5 MMcfe/d
PQ#15: 11.4 MMcfe/d
PQ#16: 16.7 MMcfe/d
PQ#17: 14.2 MMcfe/d
PQ #18: 11.7 Mmcfe/d
PQ #19: 12.5 Mmcfe/d
PQ #20: 14.8 Mmcfe/d
King 25H: 16.6 MMcfe/d
Fullen 11H: 14.5 MMcfe/d
Fullen 4H: 13.9 MMcfe/d
Biggs 5H: 12.6 MMcfe/d
Hancock Smith 2H: 11.3 MMcfe/d
Rogers 6H: 11.3 MMcfe/d
Lloyd 6H: 11.3 MMcfe/d
Ritter 4H: 16.6 MMcfe/d
Crow 2H: 17.4 MMcfe/d
Pone 7H: 13.3 MMcfe/d
Relative Rock Quality Comparison
Porosity
Marcellus
(5%)
PQ Cotton Valley
(10%)
Gulf Coast
(28%)
Permeability
Marcellus
(.01 MD)
PQ Cotton Valley
(10 MD)
Gulf Coast
(1,000 MD)
Advantages of PQ’s Cotton Valley
5
Geology: high permeability sandstones relative to low permeability shales
Multiple targets: >1,400’ thick sand column with seven benches to target
Low risk: hundreds of vertical wells with decades of production history,
cores and logs
Large resource potential: previous vertical wells didn’t efficiently drain the
producing zone – perfect application for horizontal development
Low cost: normal pressure drilling environment, simple frac design and
low operating costs
Superior location: premium Gulf Coast pricing, supportive land owners
and state/local agencies
Exceptional returns: 91% of well cost payout achieved in 1st year using a
$2.50/Mcf natural gas price assumption and most recent well cost
Cotton Valley Horizontal – Production Up with Costs Down
6
Improving Well Performance
(1) Excludes PQ #11 well which experienced mechanical issues during completion.
Recent Horizontal Cotton Valley Results
$6.9
$5.6
$5.2
$3.9
4,232
4,106
4,147
4,535
3,000
3,500
4,000
4,500
5,000
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
2013 2014 (1) 2015 PQ #20
La
te
ra
l F
e
e
t
A
ve
rag
e
D
&
C
C
o
st
D&C (8/8's) $MM Lateral Length
0
2
4
6
8
10
12
14
2011 2012 2013 2014 (1) 2015 2016
Gas
Liquids
6.3
7.4
9.1
11.9
14.2
Wells: 3 5 1 6 3 2
13.7
PQ#10 PQ#11 PQ#12 PQ#13 PQ#14 PQ#15 PQ#16 PQ#17 PQ#18 PQ #19 PQ #20 Avg. % of IP
IP Rate (Mmcfe/d) 10.7 7.9 11.7 12.3 13.5 11.4 16.7 14.2 11.7 12.5 14.8 12.5 N/A
30 Day Avg. Rate (Mmcfe/d) 9.9 6.7 10.2 13.8 14.5 13.6 16.4 14.1 11.9 11.4 11.5 12.2 98%
60 Day Avg. Rate (Mmcfe/d) 9.1 5.8 8.8 13.4 13.7 13.5 13.9 13.2 11.3 10.6 10.4 11.2 90%
90 Day Avg. Rate (Mmcfe/d) 9.0 5.2 7.7 13.6 11.7 13.0 12.3 12.2 10.9 9.8 9.9 10.5 84%
24
H
R
IP
R
at
e
(
M
M
C
FE
/D
)
1st Year Cotton Valley Profile (1)
7
Drill &
Complete
Cost
Total 1st Year
Production
Field Level
Cash Flow (2)
% of Payout
1st year
Payout
Period
$4,000 M 2.3 Bcfe (6.3 MMcfe/d) $3,624 M 91% 22 mth
(1) 2014 Avg. well performance; excluding PQ #11
(2) Price assumptions: $2.50/Mcf, $15Bbl of NGL and $40/Bbl of Oil
-
2,000
4,000
6,000
8,000
10,000
12,000
1 2 3 4 5 6 7 8 9 10 11 12
M
M
cf
e/
d
Month
Cotton Valley Horizontal Economics (1)
8
Assumptions (2)
Gross Well Cost ($MM) 4.0
EUR (Bcfe) 8.6
IP Rate (Mmcfe/d) 11.9
% Gas / Liquids 70% / 30%
IRR (%) 42%
Payback (mth) 22
(1) Excludes JV cost sharing economics
(2) 2014 Avg. well performance; excluding PQ#11;
$2.50/Mcf gas , $15 NGL/Bbl and $40 oil/Bbl
Sensitivity to Gas Prices
Economic Assumptions
$4.0 MM D&C
22%
42%
67%
0%
10%
20%
30%
40%
50%
60%
70%
80%
$2.00 $2.50 $3.00
Horizontal CV Well Economics
9
Last 9 Cotton Valley Wells: Maximum Growth with Minimal Wells
5.7
11.1
4
5
6
7
8
9
10
11
12
BCF
E
95%
Growth
in
Production
12/31/13 12/31/15
• Growth metrics above achieved with only 9 gross wells.
47.6
114
20
30
40
50
60
70
80
90
100
110
120
BCF
E
140%
Growth
in
Reserves
12/31/15
PROVED RESERVES PRODUCTION
12/31/13
10
2017 Cotton Valley Drilling Program
3-well Pad
PQ #23-25
3-well Pad
PQ #26-28PQ/CVX #22
(Drilling)
PQ #21
(WOC)
Single Well Pads
PQ #29-31
MCFADDEN-BAGLEY UNI
1
42365359740000
CUMGAS : 153,052 MCF
CUMOIL : 835 BBLS
CUMWTR : 22,183 BBLS
2/15/2006
8
2
0
0
8
2
5
0
8
3
0
0
8
3
5
0
8
4
0
0
8
4
5
0
8
5
0
0
8
5
5
0
8
6
0
0
8
6
5
0
8
7
0
0
8
7
5
0
8
8
0
0
8
8
5
0
8
9
0
0
8
9
5
0
9
0
0
0
9
0
5
0
9
1
0
0
9
1
5
0
9
2
0
0
9
2
5
0
9
3
0
0
9
3
5
0
9
4
0
0
9
4
5
0
9
5
0
0
9
5
5
0
9
6
0
0
9
6
5
0
9
7
0
0
9
7
5
0
9
8
0
0
9
8
5
0
9
9
0
0
9
9
5
0
1
0
0
0
0
1
0
0
5
0
1
0
1
0
0
1
0
1
5
0
1
0
2
0
0
1
0
2
5
0
1
0
3
0
0
1
0
3
5
0
8250 8250
8300 8300
8350 8350
8400 8400
8450 8450
8500 8500
8550 8550
8600 8600
8650 8650
8700 8700
8750 8750
8800 8800
8850 8850
8900 8900
8950 8950
9000 9000
9050 9050
9100 9100
9150 9150
9200 9200
9250 9250
9300 9300
9350 9350
9400 9400
9450 9450
9500 9500
9550 9550
9600 9600
9650 9650
9700 9700
9750 9750
9800 9800
9850 9850
9900 9900
9950 9950
10000 10000
10050 10050
10100 10100
10150 10150
10200 10200
10250 10250
10300 10300
10350 10350
10400 10400
10450 10450
10500 10500
10550 10550
SE CARTHAGE
PETRA 6/17/2013 10:36:53 AM
“C&D” Sands
Davis Sand
E4 Sands
Roseberry/Eberry Sand
Vaughn Sand
PetroQuest -- McFadden Bagley #1
GR Resistivity Den. Porosity
Cotton Valley
Benches
9,000’
10,000’
9,500’
8,500’
E Sands
Multi Bench Cotton Valley Opportunities
11
Taylor/Sexton
Bench Gross Drilling Locations*
C&D 90
Vaughn 114
Davis 182
E4 65
E 95
Eberry/Roseberry 41
Sexton/Taylor 14
Total Gross Drilling Locations 601
* Locations based on 1500’ spacing within area of
estimated economic net feet of pay determined
by offsetting vertical well logs
Cotton Valley
Drilling Locations
(1)
(1)
(1) PQ tested benches horizontally; 5 wells in E4 and 15 wells in Eberry
NOTE> All of the above benches are productive on
PQ acreage through >140 vertical wells and all
benches have been tested horizontally in close
proximity to PQ acreage
12
Cotton Valley Acreage Position
52,000 Gross Acres (100% HBP)
~600 Gross Future Locations (300 Net)
Gulf Coast – Free Cash Flow Generator
13
Houston
Lafayette
Areas of Interest:
Onshore S. LA / Shallow Water GOM
Key Operating Metrics
(1) Cash Flow = Revenues less lease operating expenses and severance taxes from Gulf Coast/Gulf of Mexico. Please see Appendix 4 for reconciliation.
(2) 2014 Capex excludes non-cash Fleetwood accruals and 2013 Capex excludes GOM acquisition.
Gulf Coast Assets: Free Cash Flow Funds Growth (1)(2)
La Cantera /
Thunder Bayou
Ten Year Drilling Success Rate: 70%
3Q16 Production (Mmcfe/d) 33
% Gas: 68%
% NGL: 11%
% Oil: 21%
Over $430MM of Free Cash Flow since 2007
0
100
200
300
400
500
600
700
800
900
Gulf Coast Cash Flow Gulf Coast Capex
$
M
M
Thunder Bayou Recompletion
14
Bottom Zone (Shut-In)
Cum Prod: 14.6 Bcfe
Original 1P: 8.6 Bcfe
Jan 17 Recompletion
154 net feet of pay
Prod Est: 50-70 MMCFE/D
3P Reserve Est: ~140 Bcfe
~$35MM in
field level
cash flow
Thunder Bayou/La Cantera 3P Value
Remaining Gross 3P Reserves ~200 Bcfe
3Q16 Cash Margin/Mcfe (1) $2.70
Remaining Gross 3P Value(undiscounted) $540 MM
PQ Weighted Avg. NRI 31%
Net Value to PQ $167 MM
Shares O/S 21,100,000
Value per Share $7.93
15
(1) Revenues (oil, gas and ngl) less lifting costs (LOE and sev taxes)
PQ’s Aggressive Response to Downturn
16
Asset sales in excess of $300 million
Completed two debt exchanges to extend maturities and reduce fixed
charges
Have repaid or extended maturity on 93% of Unsecured Notes
due 2017
Recent exchange provides $33 million of cash interest savings
over the next 18 months
New $50MM first lien term loan replaced $0 borrowing base
credit facility
Entered into JV program in East Texas
4Q16E cash costs down 46% ($10.9 million*) from 4Q15; equates to
$2.69/mcfe of margin enhancement
* Based on mid-point of 4Q16 guidance
Changes to Maturity Profile ($000s)
17
350
0
50
100
150
200
250
300
350
400
2017
-
23 14
0
50
100
150
200
250
300
350
400
2016 2017 2021 2021
12/31/15 9/30/16
244
Unsecured 2017 Notes
2021 2L Notes
2021 2L PIK Notes
Expected to be refinanced
with $50MM term loan
due 2020
18
0
10
20
30
4Q15 4Q16E
10.1
1.5
8.1
6.3
5.3
4.8
Int/Div Lifting G&A
23.5
12.6
4Q15 vs 4Q16E Cash Costs Comparison ($mm’s)
(1) Includes capitalized amounts
(2) Mid-point of 4Q16E guidance
G&A down - 9%
Lifting costs down - 22%
Int/Dividends down - 85%
(1)
(1)
$10.9MM in
savings
equates to
$2.69/mcfe (2)
(1)
(1)
2017 Gas Hedge Position (MMcf/d)
19
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
1Q17 2Q17 3Q17 4Q17
Hedged Volumes 4Q16E Gas Production 4Q17E Gas Production* **
* Assumes the mid-point of 4Q16E production guidance
**Assumes 4Q16E to 4Q17E production growth of ~100%
Average floor gas price: $3.21
Cotton Valley IRR @ $3.00: 67%
Summary
Asset Sales and Debt Exchanges Repositions Balance Sheet
Refinanced or repaid ~95% of the YE14 debt of $425MM
Refinanced debt retained the original Notes 10% interest rate
No material near-term maturities until 2021
Accomplished significant cash interest savings via debt
reduction/PIK
2017: Poised For Significant Growth through Cotton Valley
development and Thunder Bayou recompletion
Sequential production growth expected in 2017
4Q16 to 4Q17 production expected to increase ~100%
Actively hedging to lock in strong Cotton Valley economics
Interest savings from exchange coupled with production growth
provides funding for capital spend
20
21
Appendix
Appendix 1 - Hedging Positions
22
Natural Gas Hedged Volumes (Bcfe) Price
2017 10.1 $3.21
1Q18 1.8 $3.21
Appendix 2 – Adjusted EBITDA Reconciliation
Adjusted EBITDA represents net income (loss) available to common stockholders before income tax expense (benefit), interest expense (net), preferred stock dividends, depreciation, depletion, amortization, loss
on early extinguishment of debt, share based compensation expense, gain on asset sale, non-cash gain on legal settlement, accretion of asset retirement obligation, derivative (income ) expense, costs incurred
to issue 2021 Notes and ceiling test writedowns. We have reported Adjusted EBITDA because we believe Adjusted EBITDA is a measure commonly reported and widely used by investors as an indicator of a
company’s operating performance. We believe Adjusted EBITDA assists such investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization,
which can vary significantly depending upon accounting methods or nonoperating factors such as historical cost. Adjusted EBITDA is not a calculation based on generally accepted accounting principles, or GAAP,
and should not be considered an alternative to net income in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital
expenditures, debt principal reductions and other sources and uses of cash which are disclosed in our consolidated statements of cash flows. Investors should carefully consider the specific items included in our
computation of Adjusted EBITDA. While Adjusted EBITDA has been disclosed herein to permit a more complete comparative analysis of our operating performance relative to other companies, investors should be
cautioned that Adjusted EBITDA as reported by us may not be comparable in all instances to Adjusted EBITDA as reported by other companies. Adjusted EBITDA amounts may not be fully available for
management’s discretionary use, due to certain requirements to conserve funds for capital expenditures, debt service and other commitments, and therefore management relies primarily on our GAAP results.
Adjusted EBITDA is not intended to represent net income as defined by GAAP and such information should not be considered as an alternative to net income, cash flow from operations or any other measure of
performance prescribed by GAAP in the United States. The above table reconciles net income (loss) available to common stockholders to Adjusted EBITDA for the periods presented.
23
($ in thousands) 2011 2012 2013 2014 2015 1Q16 2Q16 3Q16
Net Income (Loss) available to
common stockholders
$5,409 ($137,218) $8,943 $26,051 ($299,977) ($39,137) ($24,143) ($23,306)
Income tax expense (benefit) (1,810) 1,636 320 (2,941) 2,673 86 475 (18)
Interest expense & preferred
dividends
14,787 14,947 27,025 34,420 38,905 9,751 7,788 9,022
Depreciation, depletion, and
amortization
58,243 60,689 71,445 87,818 63,497 10,138 7,193 6,030
Share based compensation expense 4,833 6,910 4,216 5,248 4,617 442 483 436
Gain on Asset Sale - - - - (21,937) - - -
Accretion of asset retirement
obligation
2,049 2,078 1,753 2,958 3,259 608 618 670
Derivative (income) expense - 233 (233) - - - - -
Costs incurred to issue 2021 Notes - - - - - 4,740 68 5,265
Ceiling test writedown 18,907 137,100 - - 266,562 18,857 12,782 8,665
Adjusted EBITDA $102,418 $86,375 $113,469 $153,554 $57,599 $5,485 $5,264 $6,764
Appendix 3 - Discretionary Cash Flow Reconciliation
($ in thousands) 2011 2012 2013 2014 2015 1Q16 2Q16 3Q16
Net income (loss) $10,548 ($132,079) $14,082 $31,190 ($294,838) ($37,643) ($22,858) ($22,021)
Reconciling items:
Income tax expense (benefit) (1,810) 1,636 320 (2,941) 2,673 86 475 (18)
Depreciation, depletion and amortization 58,243 60,689 71,445 87,818 63,497 10,138 7,193 6,030
Share based compensation expense 4,833 6,910 4,216 5,248 4,617 442 483 436
Gain on Asset Sale - - - - (21,937) - - -
Ceiling test write down 18,907 137,100 - - 266,562 18,857 12,782 8,665
Accretion of asset retirement obligation 2,049 2,078 1,753 2,958 3,259 608 618 670
Costs incurred to issue 2021 Notes - - - - - 4,740 68 5,265
Other 625 1,114 1,240 2,188 2,259 562 248 1,180
Discretionary cash flow $93,395 $77,448 $93,056 $126,461 $26,092 ($2,210) ($991) 207
Changes in working capital accounts 26,686 13,770 (29,867) 55,370 6,789 (23,516) 3,166 (25,509)
Payments to settle asset retirement obligations (905) (2,627) (3,335) (3,623) (2,776) (464) (2,051) (369)
Net cash flow provided by operating activities $119,176 $88,591 $59,854 $178,208 $30,105 ($26,190) $124 ($25,671)
Note: Management believes that discretionary cash flow is relevant and useful information, which is commonly used by analysts, investors and other
interested parties in the oil and gas industry as a financial indicator of an oil and gas company’s ability to generate cash used to internally fund exploration
and development activities and to service debt. Discretionary cash flow is not a measure of financial performance prepared in accordance with generally
accepted accounting principles (“GAAP”) and should not be considered in isolation or as an alternative to net cash flow provided by operating activities. In
addition, since discretionary cash flow is not a term defined by GAAP, it might not be comparable to similarly titled measures used by other companies.
24
Appendix 4 – Gulf Coast/GOM Free Cash Flow Reconciliation
($ in thousands) 2007-2015
Revenues $1,005,705
Lease Operating Expense (184,505)
Severance Tax (25,480)
Field level cash flow $795,720
Capital Expenditures (1) (361,794)
Free Cash Flow $433,926
25
(1) 2014 Capex excludes non-cash Fleetwood accruals and 2013 Capex excludes GOM acquisition.
Appendix 5 - Panola County Cotton Valley – Room to Run
26
Legend
Cotton Valley Wells
PQ CV Vertical Wells
PQ CV Horizontal Wells
PQ Area
of Mutual
Interest
Carthage Field Area
– 4.4 TCF of
Unrisked Resource
Potential
2.2 Tcfe of
CV/TP/Bossier
Unrisked
Resource
Potential
Appendix 6 - Cotton Valley Horizontal – Horizontal Uplift
27
Horizontal Completions Realizing 12x EUR Uplift vs. Vertical Wells
(1) Ryder Scott estimate excluding PQ #11 well which experienced mechanical issues during completion
0.7
8.6
0
1
2
3
4
5
6
7
8
9
10
61 Vertical Wells 2014 Horizontal Wells (1)
A
vg
.
B
cfe
/
W
e
ll
Company Information
28
400 East Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
Phone: (337) 232-7028
Fax: (337) 232-0044
www.petroquest.com
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