Oct 31, 2017 - UNITS FORMED FOR FUTURE DRILLING .... 3 Average price differentials ranges for oil and natural gas exclud
3Q 2017 Investor Update Rick Muncrief, Chairman and CEO Nov. 2, 2017
Recent Highlights
Raising 2017 oil growth guidance from 40% to 45% year-over-year Current oil production averaging 75,000 BBL/D Increasing EURs in the Williston to 1,000 MBOE 67% increase unhedged margin per BOE past 12 months, $9.68 to $16.20 Closed joint venture with Howard Energy Partners, $349MM in cash Signed PSA Legacy San Juan Dry Gas, $169MM with closing by year-end
2
WPX Executing on Strategy UNHEDGED DISCRETIONARY CASH FLOW
ANNUALIZED ADJ. EBITDAX2
(NET DEBT / ANNUALIZED ADJ. EBITDAX)
$16.20 $16
$700
5.0
5.5x
$600 4.0
4.3x
$500
3.9x $400
3.4x
$300
3.0
2.0
$200
NET DEBT/ADJ. EBITDAX
ADJ. EBITDAX ($MM)
($ PER BOE)
$18
6.0
$14 PER BOE
$800
$12 $10
$10.45
$9.68
$9.39
4Q16
1Q17
$8 $6 $4
1.0
$100
$2
$0 4Q16
1Q17
ANNUALIZED ADJ. EBITDAX
2Q17
3Q17 1
0.0
NET DEBT/ANNUALIZED ADJ. EBITDAX
$2Q17
3Q17
Deleveraging and Margin Expansion Progressing Rapidly
1. 2.
3Q net debt includes $349MM in proceeds received from Howard Energy Partners on 10/18/2017. Quarterly Adjusted EBITDAX multiplied by four periods
3
WPX 2018 Guidance Highlights CASH FLOW NEUTRAL 20181
OIL GROWTH 40% - 45%
TOTAL CAPITAL $1.1B - $1.2B
NET DEBT TTM ADJ. EBITDAX
BELOW 2.5X 4Q’18
FLAT RIG COUNT ~10 RIGS
COMMODITY MIX ~60% OIL ~80% LIQUIDS
Free Cash Flow 2019 and Beyond Leverage Below 2.0x 1.
Includes proceeds for non-core asset sales.
4
Operational Update Clay Gaspar, Chief Operating Officer
Delaware Basin
STRONG WELL PERFORMANCE 1.5 MILE LATERALS • LINDSAY 10 15-15H 30-DAY AVG: ~3,000 BOE (54% OIL) • LINDSAY 10 15-16H 30-DAY AVG: 3,128 BOE (53% OIL) • LINDSAY 10 15-17H 30-DAY AVG: 3,020 BOE (53% OIL) • LINDSAY 10 15-18H 30-DAY AVG: 2,902 BOE (56% OIL) • LINDSAY 10 15-19H 30-DAY AVG: 3,301 BOE (53% OIL)
4Q PLANNED ACTIVITY
DROPPING A RIG & EXITING 2017 WITH 20-25 DUCS
59% OIL GROWTH SINCE 3Q16
25 20 MBBL/D
GROWING OIL VOLUMES
15 10 5 0 3Q16
4Q16
1Q17
2Q17
3Q17
CLOSED MIDSTREAM JV AGREEMENT
RECEIVED $349MM FROM HOWARD ENERGY PARTNERS
6
Delaware – Drilling More Lateral Feet in 2018
2017
MORE LATERAL FEET DRILLED WITH FLAT RIG COUNT
~515,000’
2018
+20%
~625,000’
► ► ►
Average lateral drilled 6,150’ ~7 rig average Landed in 8 different zones
LATERAL FEET DRILLED IN 2017
LATERAL FEET TO BE DRILLED IN 2018
► ► ►
Average lateral ~7,500’ 6-7 rigs Primary target: ► Upper/Lower WCA
+20% MORE LATERAL 7
Delaware – Completing More Lateral Feet in 2018
2017
MORE LATERAL FEET COMPLETED WITH FLAT RIG COUNT
~350,000’
2018
+50%
~540,000’
►
2 frac crews
►
3 frac crews
LATERAL FEET COMPLETED IN 2017
LATERAL FEET TO BE COMPLETED IN 2018
+50% MORE LATERAL 8
Williston Basin
RAISING THE TYPE CURVE MOVING TO 1,000 MBOE CURVE (81% OIL)
(BLENDED THREE FORKS AND MIDDLE BAKKEN)
GROWING OIL VOLUMES
MBBL/D
VS. 1,000 MBOE TYPE CURVE
160 140 CUM MBOE
2016-2017 PERFORMANCE
180
81% OIL GROWTH SINCE 3Q16
120 100 80
2016 AVG.
60 40
35
20
30
0 0
25
30
60
20 15
150
180
70
5 0 4Q16
1Q17
2Q17
STRONG WELL PERFORMANCE 2018 DRILLING PROGRAM:
FOCUSED ON NORTH SUNDAY ISLAND
RECENT 24-HOUR IPS:
60
3Q17
MANDAN NORTH 13-24HW: 4,464 BOE/D (81% OIL) HIDATSA NORTH 14-23HX: 4,081 BOE/D (81% OIL)
CUM MBOE
3Q16
90 120 DAYS ON PRODUCTION
NORTH SUNDAY ISLAND
80
10
2017 AVG.
50 40 30 20 10 0 0
DAYS ON PRODUCTION
30
9
San Juan Basin
SIGNED PSA LEGACY SAN JUAN DRY GAS EXPECTED CLOSE BY YE 2017
SAN JUAN COUNTY
UNITS FORMED FOR FUTURE DRILLING WEST LYBROOK UNIT
STRONG WELL PERFORMANCE
SANDOVAL COUNTY
RODEO UNIT
WELL RESULTS FROM RODEO UNIT:
RIO ARRIBA COUNTY
ESCAVADA UNITS
30-DAY AVG. CUM PRODUCTION: 28 MBOE (71% OIL)
4Q 2017 PLANNED ACTIVITY
120
EXITING 2017 WITH 12 DUCS AND 0 RIGS
RODEO UNIT PERFORMANCE NORMALIZED TO 7,500’
100
GROWING OIL VOLUMES 12
MBBL/D
10
CUM MBOE
50% OIL GROWTH SINCE 3Q16
80 60 40
8 6
20
4 2
0 0
0 3Q16
4Q16
1Q17
2Q17
3Q17
10
20
30
40
50
60
70
80
DAYS ON PRODUCTION
10
Financial Update Kevin Vann, Chief Financial Officer
rd Quarter in millions, except production numbers 3Dollars Results
3Q
YTD
2017
2016
2017
2016
64.8
38.9
56.6
40.4
204
205
201
199
NGLs (Mbbl/d)
13.3
11.4
12.8
9.7
Equivalent (MBOE/d)
112.0
84.4
102.8
83.2
Adjusted EBITDAX
$188
$115
$455
$340
Adjusted Net Income (Loss) from Continuing Operations
($40)
($59)
($157)
($201)
Capital Expenditures
$3151
$160
$911
$424
Average Daily Production Oil (Mbbl/d) Gas (MMcf/d)
1. Including
$30 million for items not associated with D&C activity such as infrastructure development that was reimbursed in the JV closing process, facilities construction and land. Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant GAAP measures is provided in this presentation.
12
WPX Financial Transformation Underway
45%
UNHEDGED DISCRETIONARY CASH FLOW
OIL
(MBBLS/D)
70
IN OIL VOLUMES
64.8 58.6
60
67%
50
IN UNHEDGED DISCRETIONARY CASH FLOW
$12
40
$10
30
$8
4Q16
$6
($ PER BOE)
$5.87
$5.75
$7 $4.83
$5
$4.61
$6
$5.27
$4.80 $4.09
4Q16
1Q17
2Q17
3Q17
$138 $120 $93
$60 $20 $4Q16
$19.27
$174
$80
1Q17
2Q17
3Q17
4Q16
1Q17
2Q17
3Q17
21%
($ PER BOE)
IN INTEREST EXP ($ PER BOE)
$18.11
$18
$17.78
39%
$18 $17
$16.39
$17
IN G&A ($ PER BOE)
$16
15%
$16
$1
$-
$100
$40
$19
$2
$1
$120
$2 3Q17
$20
$3
$2
$10.45
$19
$4
$3
$9.39
DD&A
$6.71
$5
$4
2Q17
($ PER BOE)
$8
$9.68
$4
G&A
INTEREST EXPENSE $7
1Q17
($ IN MILLIONS)
$180 $140
$-
0
$200 $160
$6
10
IN UNHEDGED ADJUSTED EBITDAX
$16.20
$14
20
87%
($ PER BOE)
$16
46.1
44.7
$18
UNHEDGED ADJUSTED EBITDAX
$15
$4Q16
1Q17
2Q17
3Q17
$15
NOTE: Percentage change is based on the change from 4Q’16 to 3Q’17.
4Q16
1Q17
2Q17
3Q17
IN DD&A ($ PER BOE)
13
2018 Full-Year Guidance Production
FY 2018
Expenses
Oil Mbbl/d
82.0 – 88.0
$ per BOE
Natural Gas MMcf/d
170 – 190
LOE
NGL Mbbl/d
21.5 – 23.0
GP&T
1.75 – 2.25
Total MBOE/d
132 – 143
Production Tax
2.75 – 3.00
Cash Operating
$9.75 – $11.00
DD&A
$17.00 – $19.00
Cap Ex ($ in Millions) D&C Capital1 Midstream Capital Total2
Avg. Price Differentials3
FY 2018 $1,040 – $1,110 $1,100 – $1,200
FY 2018 ($5.00) – ($6.00)
NYMEX – Nat. Gas (Mcf)
($1.00) – ($1.25)
NGL – % of WTI
$5.25 – $5.75
60 – 90
Oil – WTI per barrel
Net Realized Price4
FY 2018
FY 2018 38% – 42%
G&A – Cash
$2.40 – $2.60
G&A – Non-Cash
$0.65 – $0.75
Exploration
$1.45 – $1.55
Interest Expense
$3.65 – $3.95
Tax Rate Tax
Provision5
FY 2018 33% – 37%
COMMODITY MIX6
~60% OIL ~80% LIQUIDS
OIL PRODUCTION
40-45% YOY 2018 RIG COUNT DELAWARE:
1 Includes
non-operated wells, facilities cost and artificial lift. any acquisition and land capital. 3 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 4 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 5 Rate does not reflect potential valuation allowance on deferred tax assets. 6. Based on midpoint of guidance 2 Excludes
WILLISTON: SAN JUAN:
6-7 2-3 0-1 14
WPX Continued Focus on Shareholder Value Paying Off WILLISTON
MULTI-YEAR STRATEGY
SAN JUAN GALLUP
HEADQUARTERS TULSA, OK
DELAWARE
RETURNS
AHEAD OF SCHEDULE
2018
MARGINS
EXECUTION DISCIPLINE FOCUS
LEVERAGE 15
Appendix
Updated 2017 Full-Year Guidance (Includes Impact of San Juan Legacy Sale) Production
FY 2017
Expenses
Oil Mbbl/d
59.0 – 62.0
$ per BOE
Natural Gas MMcf/d
200 – 215
LOE
NGL Mbbl/d
14.0 – 19.0
GP&T
2.00 – 2.50
Total MBOE/d
106 – 117
Production Tax
2.25 – 2.75
Cash Operating
$9.50 – $11.00
DD&A
$18.00 – $19.00
Cap Ex ($ in Millions) D&C
Capital1
Delaware Infrastructure2 Total3
Avg. Price Differentials4
$940 – $1,010 50 – 60 $990 – $1,070
FY 2017
Oil – WTI per barrel
($6.00) – ($7.00)
NYMEX – Nat. Gas (Mcf)
($0.80) – ($1.00)
NGL – % of WTI
FY 2017
$5.25 – $5.75
G&A – Cash
$3.00 – $3.25
G&A – Non Cash
$0.85 – $0.90
Exploration7
$1.75 – $1.95
Interest Expense
$4.50 – $4.90
Tax Rate Net Realized Price5
FY 2017
Tax Provision6
FY 2017 33% – 37%
38% – 42%
1 Includes
non-operated wells and wells which include additional science work. Incudes $49MM of capital associated with the midstream infrastructure reimbursed through JV by Howard Energy. 3 Excludes any acquisition and land capital. 4 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 5 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 6 Rate does not reflect potential valuation allowance on deferred tax assets. 7 Excludes $23MM of lease expiration expense recorded in the 1st quarter. 2
17
WPX Liquidity, Hedges and Debt Maturities Liquidity Cash and Equivalents @ (10/31/2017)
$75
Revolver Capacity
$1,125
Liquidity
$1,200
Dollars listed in millions
% of Production Hedged1
STRONG LIQUIDITY
STRONG HEDGE POSITION CREATES CERTAINTY FOR DRILLING$3.93 PROGRAM
100% 80% 60%
$2.97
$52.69
40% 20% 0%
2018
Oil: 55,500 bbl/d Hedged ► $52.69 per barrel Gas: 140,000 mmbtu/d ► $2.97 per MMBtu
Natural Gas
2019
2018
Oil
Oil: 22,000 bbl/d Hedged ► $50.85 per barrel
Senior Debt Maturities $1,200
$ MM
$1,000 $800 $600
$1,100
$400 $200
$350
$500
$650
2023
2024
Senior Notes
Senior Notes
$0 2017
2018
2019
2020 Senior Notes
1 Based
on midpoint of guidance
2021
2022 Senior Notes
18
WPX Hedges
Updated: October 31, 2017 Oct – Dec 2017 Volume/Day Average Price
2018 Volume/Day Average Price
2019 Volume/Day Average Price
Crude Oil (bbl) Fixed Price Swaps1
50,638
$50.23
55,500
$52.69
22,000
$50.85
Fixed Price Calls
4,500
$56.47
13,000
$58.89
5,000
$54.08
15,000
($0.62)
17,521
($0.91)
20,000
($0.93)
Fixed Price Swaps2
170,000
$3.02
140,000
$2.97
-
-
Fixed Price Calls
15,327
$4.50
16,301
$4.75
-
-
-
-
42,500
($0.08)
30,000
($0.09)
72,500
($0.20)
47,500
($0.31)
25,000
($0.39)
-
-
15,000
$0.93
45,000
$0.07
97,500
($0.18)
40,000
($0.30)
-
-
Crude Oil Basis (bbl) Midland Basis Swaps Natural Gas (MMBtu)
Natural Gas Basis (MMBtu) Houston Ship Channel Basis Swaps Permian Basis Swaps West Texas Basis Swaps San Juan Basis Swaps
In addition to several crude oil swaps, WPX entered into calendar monthly average(CMA) Nymex roll swaps which provide pricing adjustments to the trade month versus the delivery month for contract pricing. CMA Nymex roll swaps for 2018 total 20,000 bbls/d at a weighted average price of $0.03. CMA Nymex roll swaps for 2019 total 20,000 bbls/d at a weighted average price of $0.11. 2 In connection with several natural gas swaps, WPX entered into swaptions with the swap counterparties granting the counterparty the right, but not the obligation, to enter into an underlying swap with WPX in the future. Natural Gas Swaptions for 2018 total 20,000 mmbtu/d at a weighted average strike price of $3.33. 1
19
Domestic Price Realization for 2017 Oil ($/bbl) 1Q ’17
2Q’17
3Q’17
Weighted-Average Sales Price
$46.38
$43.60
Revenue Adjustments1
$(1.07)
Net Price2
Gas ($/Mcf) 1Q ’17
2Q’17
3Q’17
$44.24
$3.01
$2.65
$(1.14)
$(0.90)
$(0.50)
$45.31
$42.46
$43.34
Realized Portion of Derivatives3 $(0.77)
$2.18
Net Price Including Derivatives
$44.64
$44.54
4Q ’17
NGL ($/bbl) 4Q ’17
1Q ’17
2Q’17
3Q’17
$2.60
$22.14
$18.98
$24.31
$(0.52)
$(0.54)
$(1.29)
$(0.70)
$(0.74)
$2.51
$2.13
$2.06
$20.85
$18.28
$23.57
$1.70
$(0.11)
$0.14
$0.18
-
-
-
$45.04
$2.40
$2.27
$2.24
$20.85
$18.28
$23.57
4Q ’17
1 Natural
gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(1.21). 2 “Net Price” equals income statement product revenues by commodity, divided by volume. 3 Represents the realized settlement on derivatives that occurred during each quarter
20
Consolidated Statement of Operations (GAAP) 2016
2017
1Q
2Q
3Q
4Q
YTD
1Q
2Q
3Q
$ 97
$ 142
$ 139
$ 173
$ 551
$ 188
$ 226
$ 259
$ 673
25
24
37
39
125
44
40
38
122
5
10
12
19
46
21
23
29
73
Total product revenues
127
176
188
231
722
253
289
326
868
Net gain (loss) on derivatives
57
(154)
38
(148)
(207)
203
116
(106)
213
Gas management
31
116
25
5
177
5
8
4
17
1
-
-
-
1
-
-
-
-
216
138
251
88
693
461
413
224
1,098
152 42 16 11 9 53 39
163 41 20 16 12 55 132
150 40 19 14 10 51 31
158 40 21 19 11 55 6
623 163 76 60 42 214 208
147 48 21 19 39 43 5
171 53 21 23 21 46 8
169 58 25 26 20 42 4
487 159 67 68 80 131 17
(198) 2 126
(4) 2 437
227 10 552
(3) 2 309
22 16 1,424
(35) 4 291
(7) 8 344
(56) 3 291
(98) 15 926
90
(299)
(301)
(221)
(731)
170
69
(67)
172
(Dollars in millions)
4Q
YTD
Revenues: Product revenues: Oil sales Natural gas sales Natural gas liquid sales
Other Total revenues Costs and expenses: Depreciation, depletion and amortization Lease and facility operating Gathering, processing and transportation Taxes other than income Exploration General and administrative Gas management Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties Other-net Total costs and expenses Operating income (loss) Interest expense
(57)
(53)
(49)
(48)
(207)
(47)
(46)
(48)
(141)
Loss on extinguishment of debt
-
-
-
-
-
-
-
(17)
(17)
Investment income and other
2
(1)
-
-
1
2
-
2
4
$ 35
$ (353)
$ (350)
$ (269)
$ (937)
$ 125
$ 23
$ (130)
$ 18
35
(130)
(132)
(98)
(325)
31
(53)
20
(2)
$ -
$ (223)
$ (218)
$ (171)
$ (612)
$ 94
$ 76
$ (150)
$ 20
Income (loss) from continuing operations before income taxes Provision (benefit) for income taxes Income (loss) from continuing operations Income (loss) from discontinued operations
(12)
25
(1)
(1)
11
(2)
-
4
2
$ (12)
$ (198)
$ (219)
$ (172)
$ (601)
$ 92
$ 76
$ (146)
$ 22
Less: Dividends on preferred stock
5
6
4
3
18
4
4
3
11
Less: Loss on induced conversion of preferred stock
-
-
22
-
22
-
-
-
-
$ (17)
$ (204)
$ (245)
$ (175)
$ (641)
$ 88
$ 72
$ (149)
$ 11
Income (loss) from continuing operations
$ (5)
$ (229)
$ (244)
$ (174)
$ (652)
$ 90
$ 72
$ (153)
$ 9
Income (loss) from discontinued operations
(12)
25
(1)
(1)
11
(2)
-
4
2
$ (17)
$ (204)
$ (245)
$ (175)
$ (641)
$ 88
$ 72
$ (149)
$ 11
Net income (loss)
Net income (loss) available to WPX Energy, Inc. common stockholders Amounts available to WPX Energy, Inc. common stockholders:
Net income (loss)
21
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Non-GAAP) 2016 (Dollars in millions)
1Q
2Q
2017
3Q
4Q
YTD
1Q
2Q
3Q
4Q
YTD
Reconciliation of adjusted loss from continuing operations available to common stockholders: Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders reported
$
(5)
$ (229)
$ (244)
$ (174)
$ (652)
$
90
$
72
$ (153)
$
9
Impairments reported in exploration expense
$
-
$
-
$
-
$
-
$
-
$
23
$
-
$
-
$
23
Impairment of inventory Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties
$
-
$
-
$
4
$
-
$
4
$
-
$
-
$
-
$
-
$ (198)
$
(4)
$
227
$
(3)
$
22
$
(35)
$
(7)
$
(56)
$
(98)
Loss on extinguishment of debt
$
-
$
-
$
-
$
-
$
-
$
-
$
-
$
17
$
17
Accrual for Denver office lease
$
-
$
-
$
5
$
-
$
5
$
-
$
-
$
-
$
-
Costs related to severance and relocation
$
3
$
7
$
3
$
2
$
15
$
-
$
-
$
-
$
-
Previously capitalized costs expensed following credit facility amendment
$
4
$
-
$
-
$
-
$
4
$
-
$
-
$
-
$
-
(Gain) loss on retirement of debt
$
(3)
$
3
$
-
$
1
$
1
$
-
$
-
$
-
$
-
Unrealized MTM (gain) loss
$
76
$
223
$
20
$
190
$
509
$ (208)
$ (102)
$
120
$ (190)
Total pre-tax adjustments
$ (118)
$
229
$
259
$
190
$
560
$ (220)
$ (109)
$
81
$ (248)
Less tax effect for above items
$
43
$
(85)
$
(96)
$
(71)
$ (208)
$
$
$
(30)
Pre-tax adjustments:
83
40
$
92
Impact of state deferred tax rate change
$
14
$
-
$
-
$
1
$
15
$
(6)
$
-
$
-
$
(6)
Impact of state tax valuation allowance (annual effective tax rate method)
$
8
$
-
$
-
$
-
$
8
$
(6)
$
(34)
$
36
$
(4)
Adjustment for estimated annual effective tax rate method
$
-
$
-
$
-
$
-
$
-
$
-
$
(26)
$
26
$
-
Loss on induced conversion of preferred stock
$
-
$
-
$
22
$
-
$
22
$
-
$
-
$
-
$
-
Total adjustments, after-tax
$
(53)
$
144
$
185
$
120
$
397
Adjusted loss from continuing operations available to common stockholders
$
(58)
$
(85)
$
(59)
$
(54)
$ (255)
$ (149)
$ (129)
$
113
$ (166)
$
$
$
(40)
$ (157)
(59)
(57)
22
Reconciliation – Adjusted Diluted Loss Per Common Share 2016 (Dollars in millions)
1Q
2017
2Q
3Q
4Q
YTD
1Q
2Q
3Q
4Q
YTD
Reconciliation of adjusted diluted loss per common share: Income (loss) from continuing operations - diluted earnings per share - reported
$ (0.02)
$ (0.76)
$ (0.72)
$ (0.51)
$ (2.08)
$ 0.22
$ 0.18
$ (0.39)
$ 0.02
Impact of adjusted diluted weighted-average shares
$
-
$
-
$
-
$
-
$
-
$ 0.01
$
-
$
-
$
Impairments reported in exploration expense
$
-
$
-
$
-
$
-
$
-
$ 0.06
$
-
$
-
$ 0.06
Impairment of inventory Net (gain) loss- sales of assets, divestment of transportation contracts or impairment of producing properties
$
-
$
-
$ 0.01
$
-
$ 0.01
$
$
-
$
-
$
$ (0.72)
$ (0.01)
$ 0.67
$ (0.01)
$ 0.07
$ (0.09)
$ (0.02)
$ (0.14)
$ (0.25)
Loss on extinguishment of debt
$
-
$
-
$
$
-
$
$
-
$
-
$ 0.04
$ 0.04
Accrual for Denver office lease
$
-
$
-
$ 0.01
$
-
$ 0.02
$
-
$
-
$
-
$
-
Costs related to severance and relocation
$ 0.01
$ 0.02
$ 0.01
$ 0.01
$ 0.05
$
-
$
-
$
-
$
-
Previously capitalized costs expensed following credit facility amendment
$ 0.01
$
$
-
$
-
$ 0.01
$
-
$
-
$
-
$
-
(Gain) loss on retirement of debt
$ (0.01)
$ 0.01
$
-
$
-
$
$
-
$
-
$
-
$
-
Unrealized MTM (gain) loss
$ 0.27
$ 0.74
$ 0.06
$ 0.55
$ 1.62
$ (0.54)
$ (0.26)
$ 0.30
$ (0.48)
Total pretax adjustments
$ (0.44)
$ 0.76
$ 0.76
$ 0.55
$ 1.78
$ (0.57)
$ (0.28)
$ 0.20
$ (0.63)
Less tax effect for above items
$ 0.17
$ (0.28)
$ (0.27)
$ (0.20)
$ (0.67)
$ 0.22
$ 0.12
$ (0.07)
$ 0.23
Impact of state tax rate change
$ 0.05
$
-
$
-
$
-
$ 0.05
$ (0.01)
$
$
$ (0.01)
Impact of state valuation allowance (annual effective tax rate method)
$ 0.03
$
-
$
-
$
-
$ 0.03
$ (0.02)
$ (0.09)
$ 0.09
$ (0.01)
Adjustment for estimated annual effective tax rate method
$
-
$
-
$
-
$
-
$
$
-
$ (0.07)
$ 0.07
$
-
$
-
$
-
-
-
$
-
-
Pretax adjustments (1):
Loss on induced conversion of preferred stock
-
-
-
-
-
-
$ 0.06
$
$ 0.07
$
$ (0.19)
$ 0.48
$ 0.55
$ 0.35
$ 1.26
$ (0.38)
$ (0.32)
$ 0.29
$ (0.42)
Adjusted diluted loss per common share
$ (0.21)
$ (0.28)
$ (0.17)
$ (0.16)
$ (0.82)
$ (0.15)
$ (0.14)
$ (0.10)
$ (0.40)
276.1
300.7
341.5
344.6
313.3
410.4
423.2
398.1
396.2
Effect of dilutive securities due to adjusted loss from continuing operations available to common stockholders Adjusted diluted weighted-average shares (millions)
276.1
300.7
341.5
344.6
313.3
-
(24.1)
(25.4)
386.3
397.8
$
-
Total adjustments, after-tax Reported diluted weighted-average shares (millions)
$
-
-
-
-
(2.1)
398.1
394.1
(1) Per share impact is based on adjusted diluted weighted-average shares.
23
Reconciliation – EBITDAX (Non-GAAP) 2016 (Dollars in millions)
2017
1Q
2Q
3Q
4Q
YTD
(12)
$ (198)
$ (219)
$ (172)
$ (601)
Interest expense
57
53
49
48
207
Provision (benefit) for income taxes
35
(130)
(132)
(98)
152
163
150
9
12
241
1Q
2Q
3Q
4Q
YTD
Reconciliation of Adjusted EBITDAX Net income (loss) - reported 76
$ (146)
47
46
48
141
(325)
31
(53)
20
(2)
158
623
147
171
169
487
10
11
42
39
21
20
80
(100)
(142)
(53)
(54)
356
261
111
728
-
-
5
-
5
-
-
-
-
(198)
(4)
227
(3)
22
(35)
(7)
(56)
(98)
Loss on extinguishment of debt
-
-
-
-
-
-
-
17
17
Impairment of inventory
-
-
4
-
4
-
-
-
-
Net (gain) loss on derivatives
(57)
154
(38)
148
207
(203)
(116)
106
(213)
Net cash received (paid) related to settlement of derivatives
133
69
58
42
302
(5)
14
14
23
12
(25)
1
1
(11)
2
-
(4)
(2)
Net income (loss) - reported
$
Depreciation, depletion and amortization Exploration expenses EBITDAX Accrual for Denver office lease Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties
(Income) loss from discontinued operations Adjusted EBITDAX
$
131
$
94
$
115
$
135
$
475
$
$
92
115
$
$
152
$
$
188
$
24
22
455
Disclaimer The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company’s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized. Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based (1) upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein.
25
Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “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.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC’s website at www.sec.gov. The SEC’s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.
26
WPX Non-GAAP Disclaimer This presentation may include certain financial measures, including adjusted EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses), that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare a company’s performance. Management believes that these measures provide investors an enhanced perspective of the operating performance of the company and aid investor understanding. Management also believes that these non-GAAP measures provide useful information regarding our ability to meet future debt service, capital expenditures and working capital requirements. These non-GAAP financial measures should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.
27
