1Q'2016 Earnings Call
FIRST-QUARTER 2018
EARNINGS CALL MAY 3, 2018
WPX Today MARKET SNAPSHOT1 WILLISTON
NYSE SYMBOL: WPX MARKET CAP: $6.8B ENTERPRISE VALUE: $9.1B SHARE COUNT: 400MM
HEADQUARTERS TULSA, OK
DELAWARE
DELAWARE BASIN ~131,000 net
acres2
6,600+ gross locations3,4
WILLISTON BASIN ~85,000 net ~465 gross locations4
As of May 1, 2018 As of YE 2017 3. Primarily based on 1-mile laterals and does not include Taylor Ranch locations. 1. 2.
MIDSTREAM ASSETS Delaware JV - gas processing/oil gathering 100% owned water and gas gathering Takeaway optionality and equity ownership
acres2
4.
Includes non-op and operated locations.
2
Recent Highlights OPERATIONAL
• Delaware oil grew 149% 1Q’17 to 1Q’18 • Arikara pad produced 329,000+ barrels of oil in first 30 days • Guiding to 76 MBO/D in 2Q’18
FINANCIAL
• Renegotiated credit facility increasing capacity to $1.5B • Annualized cash interest savings ~$35MM resulting from debt tender offer
TRANSACTIONAL
• Closed San Juan Gallup sale, $700MM • Successfully tendered $500MM of debt
3
Operational Update Clay Gaspar, President & Chief Operating Officer
Crude Takeaway - Access to Premium Markets MAY-DEC 2018 Unhedged 2% Firm Midland Sales Hedged2 27%
CUSHING
ORYX II
Cushing-WTI 10%
MIDLAND
Brent 39%
Gulf Coast1 22%
HOUSTON
FY 2019 CORPUS CHRISTI
• • •
BRENT
Unhedged 7%
Less than 5% exposed to Midland spot pricing in 2018. 5%-10% exposed to Midland spot pricing in 2019. Brent, Gulf Coast, and WTI exposure consists of firm transport and firm sales commitments on BridgeTex, Cactus, and Basin pipelines.
Firm Midland Sales Hedged2 31%
Brent 31%
Gulf Coast1 20% Cushing-WTI 11%
1.Gulf 2.
Coast pricing includes LLS and Magellan East Houston Midland basis hedged @ ($0.83) for 2018 and ($0.93) for 2019
5
Gas Takeaway Creates Flow Assurance MAY-DEC 2018
Houston Ship Channel 59% STATELINE ACREAGE
Firm Sales/Hedge Volumes 41%
ATMOS AGREEMENT
WAHA
UP TO 200,000 MMBTU/D FROM WAHA TO KATY, TX
FY 2019
HOUSTON SHIP CHANNEL
WHITEWATER
UP TO 500,000 MMBTU/D FROM STATELINE TO WAHA
HENRY HUB Houston Ship Channel 69%
Firm Sales/Hedge Volumes 31%
6
1Q 2018 Delaware Basin 40 35
149%
MBBL/D
30 25 20
INCREASE IN OIL VOLUMES
15 10
1Q’17 vs. 1Q’18
5 0
1Q17
2Q17
3Q17
4Q17
1Q18
DELAWARE OIL VOLUMES
OPERATIONS
SUPPLY CHAIN
7 rigs running / 3 frac crews
Sand
25 wells on first sales in 1Q
• • •
Quinn pad results • • •
Strong production of ~610,000 BOE (70%+ oil) after 60 days 24hr-IP Average: ~2,400 BOE/D (70%+ oil) Quinn 37-36C 5H 30-Day IP: 3,273 BOE/D (71% oil)
12 portable sand silos (5MM LBS) Loving, NM sand silo (36MM LBS) Local mine access
Water •
By YE18, WPX will use 50% recycled water in our frac operations
7
1Q 2018 Williston Basin 140 MANDAN NORTH (4 WELLS)
OTTER WOMAN (5 WELLS)
JOSEPH EAGLE (3 WELLS)
HOWLING WOLF (6 WELLS)
LAWRENCE BULL (4 WELLS)
GRIZZLY PAD (5 WELLS)
2018 COMPLETIONS: WILLISTON MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
MANDAREE SOUTH (5 WELLS) ARIKARA PAD (7 WELLS)
ARIKARA PAD
EARLY TIME PERFORMANCE
120 100 CUM MBOE
BEHR PAD (3 WELLS)
80 60 40
RAPTOR PAD (3 WELLS)
YOUNG BIRD (4 WELLS)
HIDATSA NORTH (7 WELLS)
LEAD WOMAN (3 WELLS)
20 0
0
10
20
30
40
50
60
70
80
90
Normalized Days on Production
* GREEN DENOTES NORTH SUNDAY ISLAND WELLS
Mandan North & Hidasta North
Mandan North 13-24HA (4-well pad)
•
•
Produced 685,000+ BOE in 180 days (81% oil)
Arikara pad results • • •
Pad produced 329,000+ barrels of oil after 30 days 30-day IP: 75,380 BOE (Arikara 15-22HD) 24hr-IP: 3,146 BOE/D (Pad Average)
Best 24hr-IP: 5,172 BOE/D (81% oil)
Added 3rd rig in April Full-time frac and wireline crew
Normalized Days on Production
8
Financial Update Kevin Vann, Chief Financial Officer
1Q 2018 Actual Results
1Q 2018
2017
65.8 132 14.9 102.7
38.9 86 7.8 61.1
Adjusted EBITDAX
$200
$85
Adjusted Net Income (Loss) from Continuing Operations
($22)
($56)
Capital Expenditures
$349
$280
Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d)
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant GAAP measures is provided in this presentation.
10
Reducing Absolute Debt $500MM Debt Tender With Our Next Meaningful Maturity Not Until 2022 Senior Debt Maturities After Tender Offer $1,400 $1,200 $929
$ MM
$1,000 $800
$650
$600
$500
$400 $200 $0
$21 2018
2019
2020
2021
2022
2023
2024
2025
11
Portfolio Transformation Driving High Margins $28
Shifting Commodity Mix
Unhedged EBITDAX Per BOE
69%
$26
MARGIN INCREASE Unhedged EBITDAX per BOE
$24
2017 1Q’17 to 1Q’18 Excluding San Juan
WTI Increased ~20% during this period
64% 77%
$22
$20
liquids with SJ liquids without SJ
$18
NG 36%
$16
NGL 13%
$14
$12
Oil 51%
1Q17
2Q17
3Q17
4Q17
Unhedged Adj. EBITDAX per BOE With San Juan
1Q18
2017 Commodity Mix Including San Juan
NG 23% NGL 13%
Oil 64%
2017 Commodity Mix Excluding San Juan
Unhedged Adj. EBITDAX per BOE Without San Juan 12
WPX: Positioned for Long-Term Value Creation
FINANCIAL STRENGTH
OIL FOCUSED
LEVERAGE OF 1.5X DURING 2019
150 MBBL/D DURING 2022
MIDSTREAM OPTIONALITY
DEEP INVENTORY
VALUE CREATION/FLOW ASSURANCE
OF HIGH RETURNS
13
Appendix
WPX Delaware Midstream Infrastructure Overview ASSETS INCLUDED IN JV • •
Crude Gathering System: • ~125,000 Bbl/d
Gas Processing Facility:
ACREAGE DEDICATION RETAINED BY WPX
50,000 ACRES
No drilling or volume commitment
• WATER SYSTEM • GAS GATHERING
JV AGREEMENT
• 400 MMcf/d • First 200 MMcf/d train complete mid-year 2018
EDDY LEA
ASSETS WHOLLY OWNED BY WPX •
•
Stateline Gas & Water Gathering Systems: • ~200,000 Bbl/d of water disposal capacity • 150 MMcf/d of gas compression capacity
• GAS PROCESSING PLANT • CRUDE GATHERING
NEW MEXICO TEXAS
ORYX II
LOVING
UP TO 100,000 BBL/D FROM STATELINE TO MIDLAND & CRANE
~81,000 Net Acres Outside Stateline Dedication • WPX retains all existing midstream rights in other areas
CULBERSON
WARD REEVES
SIGNED TAKEAWAY AGREEMENTS •
Atmos Waha Takeaway Agreement
•
WhiteWater Midstream Agreement
•
WAHA
• Up to 200,000 MMBtu/d from Waha to Katy, TX • Up to 500,000 MMBtu/d from Stateline to Waha • In-service • 20% equity ownership
Oryx II Crude Takeaway Agreement
• 100,000 Bbl/d capacity • 12.5% equity ownership with option to increase to 25%
PECOS
WHITEWATER
UP TO 500,000 MMBTU/D FROM STATELINE TO WAHA
ATMOS AGREEMENT
UP TO 200,000 MMBTU/D FROM WAHA TO KATY, TX
15
WPX Asset Overview DELAWARE BASIN
WILLISTON BASIN
acres1
~131,000 net 6,600+ gross locations2,3 52% oil/18% NGLS/30% gas4
~85,000 net acres1 ~465 gross locations3 86% oil/7% NGLS/7% gas4
CHAVES
WILLIAMS
MOUNTRAIL LEA EDDY
MCKENZIE
NEW MEXICO TEXAS
MCLEAN LOVING
WINKLER
CULBERSON WARD
DUNN
MERCER
REEVES WPX OPERATED ACREAGE NON-OP ACREAGE
WPX OPERATED ACREAGE
PECOS
1.
3.
2.
4.
Acreage as of December 31, 2017. Primarily based on 1-mile laterals and does not include Taylor Ranch locations.
Includes non-op and operated locations. Based on FY 2017 production.
16
2018 Full-Year Guidance1 Production Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) D&C / Facilities Capital Land Acquisition Midstream Opportunities Total Capital Continuing Ops Midstream Equity Investments2 Total Capital and Equity Investments Continuing Ops San Juan Gallup3 Total Capital and Equity Investments
FY 2018
Avg. Price Differentials4
FY 2018
75 – 80 145 – 155 18 – 20 117 – 126
Oil – WTI per barrel NYMEX – Nat. Gas (Mcf)
($4.50) – ($5.50) ($1.00) – ($1.25)
FY 2018 $1,040 – $1,110 25 – 50 60 – 90 $1,125 – $1,250 35 – 60 $1,160 – $1,310 40 $1,200 – $1,350
Net Realized Price5 NGL – % of WTI Expenses
FY 2018 34% – 38% FY 2018
$ per BOE LOE GP&T DD&A G&A – Cash G&A – Non-Cash Exploration Interest Expense
$5.50 – $6.00 $1.40 – $1.90 $17.00 – $19.00 $2.70 – $3.10 $0.65 – $0.75 $1.50 – $1.75 $3.85 – $3.95
Production Tax Tax Provision6
7% – 9% 21% – 25%
San Juan Gallup has been reclassified as discontinued operations as of 1Q 2018. Future 25% equity ownership in Oryx II and 20% Interest with WhiteWater recorded in the investing section of the cash flow statement, “purchase of investments”. 3. San Juan Gallup capital will be reimbursed in the purchase price adjustment. 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 any potential valuation allowance on deferred tax assets. 1. 2.
17
WPX Hedges
Updated: April 27, 2018 Q2-Q4 2018 Volume/Day Average Price
2019 Volume/Day Average Price
2020 Volume/Day Average Price
Crude Oil (bbl) Fixed Price Swaps1
57,500
$52.82
34,000
$52.30
-
-
Fixed Price Calls
13,000
$58.89
5,000
$54.08
-
-
14,331
($0.83)
20,000
($0.93)
5,000
($1.16)
Fixed Price Swaps
130,000
$2.99
50,000
$2.88
-
-
Fixed Price Calls
15,984
$4.75
-
-
-
-
Houston Ship Channel Basis Swaps
42,500
($0.08)
30,000
($0.09)
-
-
Permian Basis Swaps
47,500
($0.31)
25,000
($0.39)
-
-
West Texas Basis Swaps
15,000
$0.93
35,000
$0.52
30,000
($0.72)
Mont Belvieu Ethane Swaps2
3,300
$0.29
-
-
-
-
Mont Belvieu Propane Swaps2
3,900
$0.80
-
-
-
-
900
$0.79
-
-
-
-
700
$0.91
-
-
-
-
1,800
$0.90
-
-
-
-
1,500
$1.31
-
-
-
-
Crude Oil Basis (bbl) Midland Basis Swaps Natural Gas (MMBtu)
Natural Gas Basis (MMBtu)
Natural Gas Liquids (bbl)
Conway Propane Swaps2 Mont Belvieu Iso Butane
Swaps2
Mont Belvieu Normal Butane
Swaps2
Mont Belvieu Natural Gasoline
Swaps2
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 Average price in $/gallon. 1
18
Domestic Price Realization for 2018 Oil ($/bbl) 1Q ’18
2Q’18
3Q’18
Gas ($/Mcf) 4Q ’18
1Q ’18
2Q’18
3Q’18
NGL ($/bbl) 4Q ’18
1Q ’18
Weighted-Average Sales Price
$61.21
$2.73
$24.36
Revenue Adjustments1
$(.30)
$(1.29)
$(2.22)
Net Price2 Realized Portion of Derivatives3 Net Price Including Derivatives
$60.91
$1.44
$22.14
$(9.92)
$.40
$(.69)
$50.99
$1.84
$21.45
2Q’18
3Q’18
4Q ’18
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 $(.17). 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.
19
Consolidated Statement of Operations (GAAP) 2017
1Q
(Dollars in millions)
Revenues: Product revenues: Oil sales
$
2Q
3Q
4Q
Year
1Q
$
$
$
194
$ 218
$ 308
Natural gas sales
17
16
13
21
67
Natural gas liquid sales
11
16
16
27
70
30
187 203
226 116
247 (106)
356 (210)
1,016 3
407 (69)
Commodity management
5
8
4
8
25
36
Other
-
-
-
1
1
-
395
350
145
155
1,045
374
113
141
133
155
542
161
36
41
45
46
168
55
5
6
5
8
24
18
Taxes other than income
13
19
19
28
79
30
Exploration
36
16
17
18
87
19
General and administrative
41
44
40
41
166
43
Commodity management
5
8
4
10
27
39
(31)
(7)
(112)
(11)
(161)
1
4
7
4
-
15
2
222
275
155
295
947
368
Operating income (loss)
173
75
(10)
(140)
98
6
Interest expense
(46)
Total product revenues Net gain (loss) on derivatives
Total revenues
159
2018
879
360 17
Costs and expenses: Depreciation, depletion and amortization Lease and facility operating Gathering, processing and transportation (1)
Net (gain) loss-sales of assets Other-net Total costs and expenses
(47)
(46)
(48)
(47)
(188)
Loss on extinguishment of debt
-
-
(17)
-
(17)
-
Investment income and other
2
-
2
(1)
3
(1)
Income (loss) from continuing operations before income taxes
$
Provision (benefit) for income taxes (2) Income (loss) from continuing operations
$
95
$
(3) $
92
$
88
Less: Dividends on preferred stock Net income (loss) available to WPX Energy, Inc. common stockholders
$
33
Income (loss) from discontinued operations (2) Net income (loss)
128
29
$ (73)
$ (188)
(298)
305
(168)
327
$ (378)
$ (20)
$
$
(41)
$
(26)
$
(115)
(128)
(15)
$
24
$
(16)
(31)
$
(119)
9
$
(30)
$
(119)
(251)
232
(18)
$
76
$ (146)
$ (38)
4
3
4
$
72
$ (149)
$ (42)
$ $
4
(104)
(40)
(89)
15
4
Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations
$
Income (loss) from discontinued operations Net income (loss)
91
$
(3) $
88
$
323
$ (381)
$ (24)
(251)
232
(18)
72
$ (149)
$ (42)
(40) $
(31)
Q1 2018 includes the impact of the application of ASC 606 with an offset to product revenues. The allocation of provision (benefit) for income taxes between continuing operations and discontinued operations for the second, third, and fourth quarters of 2017 is preliminary and subject to change.
(89)
1. 2.
20
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Non-GAAP)
(Dollars in millions)
2017
2018
1Q
1Q
Reconciliation of adjusted income (loss) from continuing operations available to common stockholders: Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders - reported
$
91
$
(30)
Impairments reported in exploration expense
$
23
$
-
Net (gain) loss on sales of assets
$
(31)
$
1
Unrealized MTM (gain) loss
$ (208)
$
14
$ (216)
$
15
Less tax effect for above items
$
81
$
(3)
Impact of state deferred tax rate change
$
(6)
$
(4)
Impact of state tax valuation allowance (annual effective tax rate method)
$
(6)
$
-
Total adjustments, after tax
$ (147)
$
8
Adjusted income (loss) from continuing operations available to common stockholders
$
$
(22)
Pre-tax adjustments:
Total pre-tax adjustments
(56)
21
Reconciliation – Adjusted Diluted Loss Per Common Share
(Dollars in millions)
2017
2018
1Q
1Q
Reconciliation of adjusted diluted income (loss) per common share: Income (loss) from continuing operations - diluted earnings per share - reported
$
0.23
$ (0.07)
Impact of adjusted diluted weighted-average shares
$
0.01
$
-
Impairments reported in exploration expense
$
0.06
$
-
Net (gain) loss on sales of assets
$ (0.08)
$
-
Unrealized MTM (gain) loss
$ (0.54)
$
0.04
Total pretax adjustments
$ (0.56)
$
0.04
Less tax effect for above items
$
0.20
$ (0.02)
Impact of state tax rate change
$ (0.01)
$ (0.01)
Impact of state valuation allowance (annual effective tax rate method)
$ (0.02)
$
Total adjustments, after-tax
$ (0.39)
$
Adjusted diluted loss per common share
$ (0.15)
$ (0.06)
Pretax adjustments (1):
Reported diluted weighted-average shares (millions) Effect of dilutive securities due to adjusted income (loss) from continuing operations available to common stockholders Adjusted diluted weighted-average shares (millions)
410.4 (24.1) 386.3
0.01
398.6 398.6
22
Reconciliation – Adjusted EBITDAX (Non-GAAP) 2017 (Dollars in millions, except per share amounts)
1Q
2Q
2018
3Q
4Q
Year
1Q
Reconciliation of Adjusted EBITDAX Net income (loss) - reported
$
92
$
76
$ (146)
$
(38)
$
(16)
$ (115)
Interest expense
47
46
48
47
188
46
Provision (benefit) for income taxes
33
(298)
305
(168)
(128)
(15)
113
141
133
155
542
161
36
16
17
18
87
19
321
(19)
357
14
673
96
(31)
(7)
(112)
(11)
(161)
1
-
-
17
-
17
-
(203)
(116)
106
210
(3)
69
(5)
14
14
(19)
4
(55)
3
251
(232)
18
40
89
Depreciation, depletion and amortization Exploration expenses EBITDAX Net (gain) loss on sales of assets Loss on extinguishment of debt Net (gain) loss on derivatives Net cash received (paid) related to settlement of derivatives (Income) loss from discontinued operations Adjusted EBITDAX
$
85
$
123
$
150
$
212
$
570
$
200
23
Disclaimers 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.
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.
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 nonGAAP 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.
24
EARNINGS CALL MAY 3, 2018
WPX Today MARKET SNAPSHOT1 WILLISTON
NYSE SYMBOL: WPX MARKET CAP: $6.8B ENTERPRISE VALUE: $9.1B SHARE COUNT: 400MM
HEADQUARTERS TULSA, OK
DELAWARE
DELAWARE BASIN ~131,000 net
acres2
6,600+ gross locations3,4
WILLISTON BASIN ~85,000 net ~465 gross locations4
As of May 1, 2018 As of YE 2017 3. Primarily based on 1-mile laterals and does not include Taylor Ranch locations. 1. 2.
MIDSTREAM ASSETS Delaware JV - gas processing/oil gathering 100% owned water and gas gathering Takeaway optionality and equity ownership
acres2
4.
Includes non-op and operated locations.
2
Recent Highlights OPERATIONAL
• Delaware oil grew 149% 1Q’17 to 1Q’18 • Arikara pad produced 329,000+ barrels of oil in first 30 days • Guiding to 76 MBO/D in 2Q’18
FINANCIAL
• Renegotiated credit facility increasing capacity to $1.5B • Annualized cash interest savings ~$35MM resulting from debt tender offer
TRANSACTIONAL
• Closed San Juan Gallup sale, $700MM • Successfully tendered $500MM of debt
3
Operational Update Clay Gaspar, President & Chief Operating Officer
Crude Takeaway - Access to Premium Markets MAY-DEC 2018 Unhedged 2% Firm Midland Sales Hedged2 27%
CUSHING
ORYX II
Cushing-WTI 10%
MIDLAND
Brent 39%
Gulf Coast1 22%
HOUSTON
FY 2019 CORPUS CHRISTI
• • •
BRENT
Unhedged 7%
Less than 5% exposed to Midland spot pricing in 2018. 5%-10% exposed to Midland spot pricing in 2019. Brent, Gulf Coast, and WTI exposure consists of firm transport and firm sales commitments on BridgeTex, Cactus, and Basin pipelines.
Firm Midland Sales Hedged2 31%
Brent 31%
Gulf Coast1 20% Cushing-WTI 11%
1.Gulf 2.
Coast pricing includes LLS and Magellan East Houston Midland basis hedged @ ($0.83) for 2018 and ($0.93) for 2019
5
Gas Takeaway Creates Flow Assurance MAY-DEC 2018
Houston Ship Channel 59% STATELINE ACREAGE
Firm Sales/Hedge Volumes 41%
ATMOS AGREEMENT
WAHA
UP TO 200,000 MMBTU/D FROM WAHA TO KATY, TX
FY 2019
HOUSTON SHIP CHANNEL
WHITEWATER
UP TO 500,000 MMBTU/D FROM STATELINE TO WAHA
HENRY HUB Houston Ship Channel 69%
Firm Sales/Hedge Volumes 31%
6
1Q 2018 Delaware Basin 40 35
149%
MBBL/D
30 25 20
INCREASE IN OIL VOLUMES
15 10
1Q’17 vs. 1Q’18
5 0
1Q17
2Q17
3Q17
4Q17
1Q18
DELAWARE OIL VOLUMES
OPERATIONS
SUPPLY CHAIN
7 rigs running / 3 frac crews
Sand
25 wells on first sales in 1Q
• • •
Quinn pad results • • •
Strong production of ~610,000 BOE (70%+ oil) after 60 days 24hr-IP Average: ~2,400 BOE/D (70%+ oil) Quinn 37-36C 5H 30-Day IP: 3,273 BOE/D (71% oil)
12 portable sand silos (5MM LBS) Loving, NM sand silo (36MM LBS) Local mine access
Water •
By YE18, WPX will use 50% recycled water in our frac operations
7
1Q 2018 Williston Basin 140 MANDAN NORTH (4 WELLS)
OTTER WOMAN (5 WELLS)
JOSEPH EAGLE (3 WELLS)
HOWLING WOLF (6 WELLS)
LAWRENCE BULL (4 WELLS)
GRIZZLY PAD (5 WELLS)
2018 COMPLETIONS: WILLISTON MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
MANDAREE SOUTH (5 WELLS) ARIKARA PAD (7 WELLS)
ARIKARA PAD
EARLY TIME PERFORMANCE
120 100 CUM MBOE
BEHR PAD (3 WELLS)
80 60 40
RAPTOR PAD (3 WELLS)
YOUNG BIRD (4 WELLS)
HIDATSA NORTH (7 WELLS)
LEAD WOMAN (3 WELLS)
20 0
0
10
20
30
40
50
60
70
80
90
Normalized Days on Production
* GREEN DENOTES NORTH SUNDAY ISLAND WELLS
Mandan North & Hidasta North
Mandan North 13-24HA (4-well pad)
•
•
Produced 685,000+ BOE in 180 days (81% oil)
Arikara pad results • • •
Pad produced 329,000+ barrels of oil after 30 days 30-day IP: 75,380 BOE (Arikara 15-22HD) 24hr-IP: 3,146 BOE/D (Pad Average)
Best 24hr-IP: 5,172 BOE/D (81% oil)
Added 3rd rig in April Full-time frac and wireline crew
Normalized Days on Production
8
Financial Update Kevin Vann, Chief Financial Officer
1Q 2018 Actual Results
1Q 2018
2017
65.8 132 14.9 102.7
38.9 86 7.8 61.1
Adjusted EBITDAX
$200
$85
Adjusted Net Income (Loss) from Continuing Operations
($22)
($56)
Capital Expenditures
$349
$280
Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d)
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant GAAP measures is provided in this presentation.
10
Reducing Absolute Debt $500MM Debt Tender With Our Next Meaningful Maturity Not Until 2022 Senior Debt Maturities After Tender Offer $1,400 $1,200 $929
$ MM
$1,000 $800
$650
$600
$500
$400 $200 $0
$21 2018
2019
2020
2021
2022
2023
2024
2025
11
Portfolio Transformation Driving High Margins $28
Shifting Commodity Mix
Unhedged EBITDAX Per BOE
69%
$26
MARGIN INCREASE Unhedged EBITDAX per BOE
$24
2017 1Q’17 to 1Q’18 Excluding San Juan
WTI Increased ~20% during this period
64% 77%
$22
$20
liquids with SJ liquids without SJ
$18
NG 36%
$16
NGL 13%
$14
$12
Oil 51%
1Q17
2Q17
3Q17
4Q17
Unhedged Adj. EBITDAX per BOE With San Juan
1Q18
2017 Commodity Mix Including San Juan
NG 23% NGL 13%
Oil 64%
2017 Commodity Mix Excluding San Juan
Unhedged Adj. EBITDAX per BOE Without San Juan 12
WPX: Positioned for Long-Term Value Creation
FINANCIAL STRENGTH
OIL FOCUSED
LEVERAGE OF 1.5X DURING 2019
150 MBBL/D DURING 2022
MIDSTREAM OPTIONALITY
DEEP INVENTORY
VALUE CREATION/FLOW ASSURANCE
OF HIGH RETURNS
13
Appendix
WPX Delaware Midstream Infrastructure Overview ASSETS INCLUDED IN JV • •
Crude Gathering System: • ~125,000 Bbl/d
Gas Processing Facility:
ACREAGE DEDICATION RETAINED BY WPX
50,000 ACRES
No drilling or volume commitment
• WATER SYSTEM • GAS GATHERING
JV AGREEMENT
• 400 MMcf/d • First 200 MMcf/d train complete mid-year 2018
EDDY LEA
ASSETS WHOLLY OWNED BY WPX •
•
Stateline Gas & Water Gathering Systems: • ~200,000 Bbl/d of water disposal capacity • 150 MMcf/d of gas compression capacity
• GAS PROCESSING PLANT • CRUDE GATHERING
NEW MEXICO TEXAS
ORYX II
LOVING
UP TO 100,000 BBL/D FROM STATELINE TO MIDLAND & CRANE
~81,000 Net Acres Outside Stateline Dedication • WPX retains all existing midstream rights in other areas
CULBERSON
WARD REEVES
SIGNED TAKEAWAY AGREEMENTS •
Atmos Waha Takeaway Agreement
•
WhiteWater Midstream Agreement
•
WAHA
• Up to 200,000 MMBtu/d from Waha to Katy, TX • Up to 500,000 MMBtu/d from Stateline to Waha • In-service • 20% equity ownership
Oryx II Crude Takeaway Agreement
• 100,000 Bbl/d capacity • 12.5% equity ownership with option to increase to 25%
PECOS
WHITEWATER
UP TO 500,000 MMBTU/D FROM STATELINE TO WAHA
ATMOS AGREEMENT
UP TO 200,000 MMBTU/D FROM WAHA TO KATY, TX
15
WPX Asset Overview DELAWARE BASIN
WILLISTON BASIN
acres1
~131,000 net 6,600+ gross locations2,3 52% oil/18% NGLS/30% gas4
~85,000 net acres1 ~465 gross locations3 86% oil/7% NGLS/7% gas4
CHAVES
WILLIAMS
MOUNTRAIL LEA EDDY
MCKENZIE
NEW MEXICO TEXAS
MCLEAN LOVING
WINKLER
CULBERSON WARD
DUNN
MERCER
REEVES WPX OPERATED ACREAGE NON-OP ACREAGE
WPX OPERATED ACREAGE
PECOS
1.
3.
2.
4.
Acreage as of December 31, 2017. Primarily based on 1-mile laterals and does not include Taylor Ranch locations.
Includes non-op and operated locations. Based on FY 2017 production.
16
2018 Full-Year Guidance1 Production Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) D&C / Facilities Capital Land Acquisition Midstream Opportunities Total Capital Continuing Ops Midstream Equity Investments2 Total Capital and Equity Investments Continuing Ops San Juan Gallup3 Total Capital and Equity Investments
FY 2018
Avg. Price Differentials4
FY 2018
75 – 80 145 – 155 18 – 20 117 – 126
Oil – WTI per barrel NYMEX – Nat. Gas (Mcf)
($4.50) – ($5.50) ($1.00) – ($1.25)
FY 2018 $1,040 – $1,110 25 – 50 60 – 90 $1,125 – $1,250 35 – 60 $1,160 – $1,310 40 $1,200 – $1,350
Net Realized Price5 NGL – % of WTI Expenses
FY 2018 34% – 38% FY 2018
$ per BOE LOE GP&T DD&A G&A – Cash G&A – Non-Cash Exploration Interest Expense
$5.50 – $6.00 $1.40 – $1.90 $17.00 – $19.00 $2.70 – $3.10 $0.65 – $0.75 $1.50 – $1.75 $3.85 – $3.95
Production Tax Tax Provision6
7% – 9% 21% – 25%
San Juan Gallup has been reclassified as discontinued operations as of 1Q 2018. Future 25% equity ownership in Oryx II and 20% Interest with WhiteWater recorded in the investing section of the cash flow statement, “purchase of investments”. 3. San Juan Gallup capital will be reimbursed in the purchase price adjustment. 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 any potential valuation allowance on deferred tax assets. 1. 2.
17
WPX Hedges
Updated: April 27, 2018 Q2-Q4 2018 Volume/Day Average Price
2019 Volume/Day Average Price
2020 Volume/Day Average Price
Crude Oil (bbl) Fixed Price Swaps1
57,500
$52.82
34,000
$52.30
-
-
Fixed Price Calls
13,000
$58.89
5,000
$54.08
-
-
14,331
($0.83)
20,000
($0.93)
5,000
($1.16)
Fixed Price Swaps
130,000
$2.99
50,000
$2.88
-
-
Fixed Price Calls
15,984
$4.75
-
-
-
-
Houston Ship Channel Basis Swaps
42,500
($0.08)
30,000
($0.09)
-
-
Permian Basis Swaps
47,500
($0.31)
25,000
($0.39)
-
-
West Texas Basis Swaps
15,000
$0.93
35,000
$0.52
30,000
($0.72)
Mont Belvieu Ethane Swaps2
3,300
$0.29
-
-
-
-
Mont Belvieu Propane Swaps2
3,900
$0.80
-
-
-
-
900
$0.79
-
-
-
-
700
$0.91
-
-
-
-
1,800
$0.90
-
-
-
-
1,500
$1.31
-
-
-
-
Crude Oil Basis (bbl) Midland Basis Swaps Natural Gas (MMBtu)
Natural Gas Basis (MMBtu)
Natural Gas Liquids (bbl)
Conway Propane Swaps2 Mont Belvieu Iso Butane
Swaps2
Mont Belvieu Normal Butane
Swaps2
Mont Belvieu Natural Gasoline
Swaps2
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 Average price in $/gallon. 1
18
Domestic Price Realization for 2018 Oil ($/bbl) 1Q ’18
2Q’18
3Q’18
Gas ($/Mcf) 4Q ’18
1Q ’18
2Q’18
3Q’18
NGL ($/bbl) 4Q ’18
1Q ’18
Weighted-Average Sales Price
$61.21
$2.73
$24.36
Revenue Adjustments1
$(.30)
$(1.29)
$(2.22)
Net Price2 Realized Portion of Derivatives3 Net Price Including Derivatives
$60.91
$1.44
$22.14
$(9.92)
$.40
$(.69)
$50.99
$1.84
$21.45
2Q’18
3Q’18
4Q ’18
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 $(.17). 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.
19
Consolidated Statement of Operations (GAAP) 2017
1Q
(Dollars in millions)
Revenues: Product revenues: Oil sales
$
2Q
3Q
4Q
Year
1Q
$
$
$
194
$ 218
$ 308
Natural gas sales
17
16
13
21
67
Natural gas liquid sales
11
16
16
27
70
30
187 203
226 116
247 (106)
356 (210)
1,016 3
407 (69)
Commodity management
5
8
4
8
25
36
Other
-
-
-
1
1
-
395
350
145
155
1,045
374
113
141
133
155
542
161
36
41
45
46
168
55
5
6
5
8
24
18
Taxes other than income
13
19
19
28
79
30
Exploration
36
16
17
18
87
19
General and administrative
41
44
40
41
166
43
Commodity management
5
8
4
10
27
39
(31)
(7)
(112)
(11)
(161)
1
4
7
4
-
15
2
222
275
155
295
947
368
Operating income (loss)
173
75
(10)
(140)
98
6
Interest expense
(46)
Total product revenues Net gain (loss) on derivatives
Total revenues
159
2018
879
360 17
Costs and expenses: Depreciation, depletion and amortization Lease and facility operating Gathering, processing and transportation (1)
Net (gain) loss-sales of assets Other-net Total costs and expenses
(47)
(46)
(48)
(47)
(188)
Loss on extinguishment of debt
-
-
(17)
-
(17)
-
Investment income and other
2
-
2
(1)
3
(1)
Income (loss) from continuing operations before income taxes
$
Provision (benefit) for income taxes (2) Income (loss) from continuing operations
$
95
$
(3) $
92
$
88
Less: Dividends on preferred stock Net income (loss) available to WPX Energy, Inc. common stockholders
$
33
Income (loss) from discontinued operations (2) Net income (loss)
128
29
$ (73)
$ (188)
(298)
305
(168)
327
$ (378)
$ (20)
$
$
(41)
$
(26)
$
(115)
(128)
(15)
$
24
$
(16)
(31)
$
(119)
9
$
(30)
$
(119)
(251)
232
(18)
$
76
$ (146)
$ (38)
4
3
4
$
72
$ (149)
$ (42)
$ $
4
(104)
(40)
(89)
15
4
Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations
$
Income (loss) from discontinued operations Net income (loss)
91
$
(3) $
88
$
323
$ (381)
$ (24)
(251)
232
(18)
72
$ (149)
$ (42)
(40) $
(31)
Q1 2018 includes the impact of the application of ASC 606 with an offset to product revenues. The allocation of provision (benefit) for income taxes between continuing operations and discontinued operations for the second, third, and fourth quarters of 2017 is preliminary and subject to change.
(89)
1. 2.
20
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Non-GAAP)
(Dollars in millions)
2017
2018
1Q
1Q
Reconciliation of adjusted income (loss) from continuing operations available to common stockholders: Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders - reported
$
91
$
(30)
Impairments reported in exploration expense
$
23
$
-
Net (gain) loss on sales of assets
$
(31)
$
1
Unrealized MTM (gain) loss
$ (208)
$
14
$ (216)
$
15
Less tax effect for above items
$
81
$
(3)
Impact of state deferred tax rate change
$
(6)
$
(4)
Impact of state tax valuation allowance (annual effective tax rate method)
$
(6)
$
-
Total adjustments, after tax
$ (147)
$
8
Adjusted income (loss) from continuing operations available to common stockholders
$
$
(22)
Pre-tax adjustments:
Total pre-tax adjustments
(56)
21
Reconciliation – Adjusted Diluted Loss Per Common Share
(Dollars in millions)
2017
2018
1Q
1Q
Reconciliation of adjusted diluted income (loss) per common share: Income (loss) from continuing operations - diluted earnings per share - reported
$
0.23
$ (0.07)
Impact of adjusted diluted weighted-average shares
$
0.01
$
-
Impairments reported in exploration expense
$
0.06
$
-
Net (gain) loss on sales of assets
$ (0.08)
$
-
Unrealized MTM (gain) loss
$ (0.54)
$
0.04
Total pretax adjustments
$ (0.56)
$
0.04
Less tax effect for above items
$
0.20
$ (0.02)
Impact of state tax rate change
$ (0.01)
$ (0.01)
Impact of state valuation allowance (annual effective tax rate method)
$ (0.02)
$
Total adjustments, after-tax
$ (0.39)
$
Adjusted diluted loss per common share
$ (0.15)
$ (0.06)
Pretax adjustments (1):
Reported diluted weighted-average shares (millions) Effect of dilutive securities due to adjusted income (loss) from continuing operations available to common stockholders Adjusted diluted weighted-average shares (millions)
410.4 (24.1) 386.3
0.01
398.6 398.6
22
Reconciliation – Adjusted EBITDAX (Non-GAAP) 2017 (Dollars in millions, except per share amounts)
1Q
2Q
2018
3Q
4Q
Year
1Q
Reconciliation of Adjusted EBITDAX Net income (loss) - reported
$
92
$
76
$ (146)
$
(38)
$
(16)
$ (115)
Interest expense
47
46
48
47
188
46
Provision (benefit) for income taxes
33
(298)
305
(168)
(128)
(15)
113
141
133
155
542
161
36
16
17
18
87
19
321
(19)
357
14
673
96
(31)
(7)
(112)
(11)
(161)
1
-
-
17
-
17
-
(203)
(116)
106
210
(3)
69
(5)
14
14
(19)
4
(55)
3
251
(232)
18
40
89
Depreciation, depletion and amortization Exploration expenses EBITDAX Net (gain) loss on sales of assets Loss on extinguishment of debt Net (gain) loss on derivatives Net cash received (paid) related to settlement of derivatives (Income) loss from discontinued operations Adjusted EBITDAX
$
85
$
123
$
150
$
212
$
570
$
200
23
Disclaimers 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.
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.
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 nonGAAP 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.
24
