3rd quarter earnings call - amazon web services completions accelerating production and increasing...

3rd Quarter Earnings Call Rick Muncrief, Chief Executive Officer

November 5, 2014

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.

2 WPX 3rd Quarter Earnings Call | November 5, 2014

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.


Domestic oil production of 25.8 Mbbl/d, which grew 52% 3Q ’14 vs. 3Q ’13

Current domestic oil production rate of 29.0 Mbbl/d

Oil and liquids accounted for 56% total domestic production revenues

► YTD ’14 shows 40% increase in domestic oil revenues

Cash flow from operations grew 50% through YTD 3Q ’14 vs. 3Q ’13

In fewer than 18 months after initial production, San Juan sold its one millionth net barrel of oil

► Averaging 1+ rigs

High-grading our portfolio continues

WPX 3rd Quarter Earnings Call | November 5, 2014 4

3rd Quarter Highlights

Domestic Production – Normalized Growth


► Equivalent production expected to be up by 9%

► Oil production expected to be up by +60%

4Q ’14 Domestic Growth vs. 4Q ’13

0

200

400

600

800

1000

1200

4Q ’13 1Q ’14 2Q ’14 3Q ’14 4Q ’14

Production Growth Excluding Legacy, Powder River and International

Oil NGLs/Natural Gas Midpoint Guidance

Williston Efficiencies Driving Performance

Continued strong production growth

► Averaged 20.1 Mbbl/d in 3Q ’14

► Oil production up 44% 3Q ’14 vs. 3Q ’13

Larger stimulations exceeding blended infill EUR type curve1

► Ruby 31-30HX exceeds type curve by 25 Mbo, or 53% in the first 86 days2

► Alfred Old Dog 30-31HD exceeds type curve by 13.8 Mbo, or 35% in the first 67 days2

► Morsette 35-26HD exceeds type curve by 21.7 Mbo, or 74% in the first 47 days2

Relentless focus on cost controls

► Drilling and completion

► Facilities design

► Lease operating expense

$305

$236

$184

$-

$50

$100

$150

$200

$250

$300

$350

2012 2013 2014

Average Drilling Cost per Foot


1 Blended infill Middle Bakken and Three Forks type curve using 3MM-pound stimulations.

2 Days of production post clean out.

Larger Completions Accelerating Production and Increasing Returns


0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

0 30 60 90

Cu

mu

lati

ve B

arre

ls o

f O

il

Days After Clean Out

RUBY 31-30HX (3F) RUBY 31-30HA (MB)

RUBY 31-30HW (3F) ALFRED OLD DOG 30-31HD(MB)

MORSETTE 35-26HD (MB) MORSETTE 35-26HZ (3F)

MORSETTE 35-26HX (MB) ALFRED OLD DOG 19-18HD (MB)

2015 BLENDED TYPE CURVE 3MM# Proppant

San Juan Gallup Accelerating Production Growth

Rapidly growing oil production

► Averaged 3.9 Mbbl/d in 3Q ’14



Added 3rd rig in Gallup

► Increasing spuds from 40 to 48 in 2014

► Record spud-to-rig release of 9.5 days with a TD of 10,390′

Acquired two 7,500′ laterals drilled by 3rd party

► Spud first WPX-operated 7,500′ lateral

Signed 5-year 10,000 bbl/d rail deal at a planned unit train facility

► Expected in-service date of 3Q ’15

► Close proximity to premium West Coast markets and easy access to Gulf Coast

► Additional capacity available as basin production grows


Mancos Gallup Drilling Metrics by Quarter

38.9

26.9

16.6 16.2 16.3 14.7

12.6

0

2

4

6

8

10

12

14

16

0

5

10

15

20

25

30

35

40

1Q-2013 2Q-2013 3Q-2013 4Q-2013 1Q-2014 2Q-2014 3Q-2014

We

ll C

ou

nt

Day

s

Spud to Release

Avg

Rig

Ct

1

.0

Avg

Rig

Ct

1

.0

Avg

Rig

Ct

1

.0

Avg

Rig

Ct

1

.0

Avg

Rig

Ct

1

.6

Avg

Rig

Ct

2

.0

Avg

Rig

C

t 2

.3

San Juan Gallup Production (MBOE per day)

1.7 2.2

3.8

6.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

4Q '13 1Q '14 2Q '14 3Q '14

MB

OE

per

day

Piceance: Ryan Gulch Efficiencies and Deep Resource Assessment

3rd quarter activity ► Spud 70 wells in 3Q

► Spud 209 wells 3Q YTD

3rd quarter net production 640 MMcfe/d

► Natural gas 542 MMcf/d

► NGL 14.5 Mbbl/d

► Oil 1.7 Mbbl/d Highlights from Ryan Gulch

► Drilled 1st Ryan Gulch vertical deep well test

► Record well drilled 8.1 days ► 31% improvement from 2013 average of 11.8 days

► Water disposal costs decreased from $2.55/bbl to $0.64/bbl in 2014

Niobrara update

► Parachute horizontal test drilled and completed ► Peak rate of 14 MMcfe/d @ 7,200 psi

► Testing additional intervals in the Mancos Group

Deep resource assessment – Niobrara/Mancos

► Stacked-pay potential

► Testing new fields – Ryan Gulch


Niobrara (1,430 ft)

Iles (650 ft)

Lower Williams Fork

(2,500 ft)

Mancos B (1,100 ft)

Loyd (625 ft)

Sego (600 ft)

Castlegate (650 ft)

Man

cos/N

iob

rara Gro

up

(5

,00

0 ft)

Financial Results Kevin Vann, Chief Financial Officer

3rd Quarter Results


Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.

Dollars in millions, except production numbers

3Q YTD Avg

2014 2013 2014 2013

Daily Production

Gas (MMcf/d) 766 839 797 835

Oil (Mbbl/d) 32.3 22.3 28.6 21.0

NGLs (Mbbl/d) 17.5 20.1 18.0 21.0

Equivalent (MMcfe/d) 1,065 1,094 1,076 1,087

Adjusted EBITDAX 230 174 797 564

Adjusted Net Income (Loss) from Continuing Operations (4) (80) 30 (173)

Capital Expenditures 597 295 1,325 843

Production Previous Disc. Ops Current Natural Gas MMcf/d 920 - 950 (170) 755 - 775

Oil Mbbl/d 30.2 - 32.0 (6.1) 24.2 - 25.8

NGL Mbbl/d 18.0 - 19.0 (0.4) 17.0 - 18.07

Total MMcfe/d 1,209 - 1,256 (209) 1,002 - 1,038

Expenses Previous Current $ per Mcfe

LOE $0.73 - $0.75 $0.67 - $0.70

DD&A 1.95 - 2.00 2.15 - 2.20

GP&T 0.92 - 0.97 0.89 - 0.94

SG&A 0.63 - 0.67 0.71 - 0.75

Production Tax 0.42 - 0.46 0.38 - 0.42

$ in Millions

Gas Management (Inc)/Exp4 ($25) - ($35) ($25) - ($35)

Exploration 85 - 95 120 - 130

Interest Expense 125 - 130 125 - 130

Equity (Earnings) Loss (20) - (25) –

% of Net Realized Price3 Previous Current Natural Gas - NYMEX 80% - 86% 80% - 86%

Oil - WTI 81% - 87% 83% - 89%

NGL - OPIS/Mt Belvieu 76% - 80% 76% - 80%

Number of Rigs Previous Current Piceance Valley 6 6

Piceance Highlands 2 2

Piceance Niobrara 1 1

Total Piceance 9 9

Williston 5 5

San Juan Gallup 2 3

Total Rigs 16 17

Cap Ex ($ in Millions) Previous Current Growth Basins

Piceance $475 - $495 $475 - $495

Williston 640 - 650 630 - 660

San Juan Gallup 210 - 220 280 - 290

Other

Appalachia 20 - 30 20 - 30

Other1 10 - 15 10 - 15

Land 75 - 85 75 - 85

Exploration 40 - 45 40 - 45

Total Domestic $1,470 - $1,540 $1,530 - $1,620

International2 90 - 100 –

Total Capital6 $1,560- $1,640 $1,530 - $1,620

2014 Full-Year Domestic Guidance – Excludes Powder River and International


1 Other includes expenditures for Powder River and other basins. 2 International is a self-funded entity and does not receive any cash from WPX Energy. 3 Percentage of realized price ranges for NYMEX, WTI and OPIS excludes hedges, but

includes basis differential and revenue adjustments. 4 Gas Management impact is net of revenues and expenses, and includes unutilized

transport capacity. Includes impact of realized hedges on non-equity production. 5 Excludes impact of $9MM tax expense accrual for new legislation in 1Q ’14. 6 Excludes acquisition capital. 7 Current guidance assumes lower ethane recovery levels than the previous guidance.

Tax Rate Previous Current Tax Provision5 33% - 37% 33% - 37%

WPX Executing on 20/20 Vision

High-grading our portfolio continues

Cash flow from operations grew 50% through YTD 3Q ’14 vs. 3Q ’13

Rockies Express transportation deal rolling off mid-November

► More than $100MM in EBITDAX improvement

Strong balance sheet

► Enables flexibility in lower commodity price environment

► Provides ability to be opportunistic

► New $1.5B credit facility through 2019

2015 guidance released by early December


Appendix

2013-14 Daily Production


2013 Avg 2014 Avg 1Q 2Q 3Q 4Q Total 1Q 2Q 3Q Total

Domestic Production

Gas (MMcf/d) 822 811 821 790 811 795 791 746 777

Oil (Mbbl/d) 13.8 15.1 17.1 18.9 16.2 19.3 23.7 25.8 23.0

NGLs (Mbbl/d) 21.2 20.8 19.7 19.7 20.3 17.6 17.9 17.1 17.5

MMcfe/d 1,032 1,026 1,041 1,021 1,030 1,016 1,040 1,003 1,020

International Production

Gas (MMcf/d) 17 18 19 19 18 19 20 21 20

Oil (Mbbl/d) 5.6 6.1 5.3 5.3 5.6 5.2 5.2 6.5 5.6

NGLs (Mbbl/d) 0.5 0.5 0.5 0.4 0.5 0.5 0.4 0.4 0.4

MMcfe/d 53 57 53 53 54 53 54 62 56

Total Production

Gas (MMcf/d) 839 829 839 809 829 814 811 766 797

Oil (Mbbl/d) 19.4 21.2 22.3 24.2 21.8 24.5 28.9 32.3 28.6

NGLs (Mbbl/d) 21.6 21.3 20.1 20.1 20.8 18.1 18.3 17.5 18.0

MMcfe/d 1,085 1,083 1,094 1,074 1,084 1,069 1,095 1,065 1,076

Note: Excludes discontinued operations (Powder River production)

Hedging Overview


Balance of 20141 2015

Volume/Day Average Price Volume/Day Average Price

Natural Gas (MMBtu)

Fixed Price Swaps2 315,000 $4.19 272,055 $4.31

Costless Collars 190,000 $4.04 - $4.66 50,000 $4.00 - $4.50

Natural Gas Basis (MMBtu)

Dominion Basis Swaps 38,750 ($0.73)

MidCon Basis Swaps 30,000 ($0.19) 12,500 ($0.16)

Rockies Basis Swaps 142,500 ($0.15) 150,000 ($0.11)

San Juan Basis Swaps 255,000 ($0.15) 85,000 ($0.10)

SoCal Basis Swaps 72,500 $0.13 20,000 $0.18

Crude Oil (bbl)

Fixed Price Swaps2 14,975 $96.01 20,236 $94.88

Natural Gas Liquids (bbl)3

Ethane Swaps 3,261 $0.29

Propane Swaps 489 $1.17

Isobutane Swaps 652 $1.37

Normal Butane Swaps 652 $1.34

Natural Gasoline Swaps 1,630 $2.06

1 Balance of 2014 is October - December. 2 In connection with several natural gas and crude oil swaps, we entered into swaptions with the swap counterparties granting the counterparty the right, but not the obligation,

to enter into an underlying swap with us in the future. 3 All Natural Gas Liquids swaps are priced at Mont Belvieu.

As of 10/28/2014

Domestic Price Realization for 2014


Gas ($/Mcf) NGL ($/bbl) Oil ($/bbl)

1Q ’14 2Q ’14 3Q ’14 4Q ’14 1Q ’14 2Q ’14 3Q ’14 4Q ’14 1Q ’14 2Q ’14 3Q ’14 4Q ’14

Weighted-Average Sales Price $4.84 $4.00 $3.30 $49.14 $44.18 $43.42 $88.40 $88.94 $84.76

Revenue Adjustments1 (0.42) (.34) (.38) (10.87) (10.60) (9.78) (2.16) .30 (.65)

Hedge Impact 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Net Price(2) $4.42 $3.66 $2.92 $38.27 $33.58 $33.64 $86.24 $89.24 $84.11

Realized Portion of Derivatives Not Designated as Hedges(3) (0.63) (.13) .15 (0.48) (.30) .66 (2.30) (3.40) (.70)

Net Price Including All Derivatives

$3.79 $3.53 $3.07 $37.79 $33.28 $34.30 $83.94 $85.84 $83.41

1Q ’14 2Q ’14 3Q ’14 4Q ’14

Impact of Rockies Sale-for-Resale Contract Expires in Nov. ’14

$(0.38) $(0.40)

$(0.61)

Weighted-Average Sales Price Excluding Rex

$4.17 $3.93 $3.68

3Q: Rockies sale-for-resale agreement impacted net realized gas price ($0.61). Contract expires in November 2014.

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 $(1.25).

2 “Net Price” equals income statement product revenues by commodity, divided by volume.

3 Represents the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes.

Piceance Basin

18

Niobrara Dedicated Rig Mesaverde Rigs

WPX 3rd Quarter Earnings Call | November 5, 2014

Williston Basin

WPX 3rd Quarter Earnings Call | November 5, 2014

WPX-operated rig

19

Williston Netback Price Analysis

Assumed 4Q 2014 total netback of WTI less $12 - $13 per barrel

Our current sales agreements consist of the following:

► Basin sales: Arrow CDP WASP and lease sales

► Rail: Receive Gulf, West and East Coast pricing

► Enbridge: Receive Clearbrook, Minn., price

Our sales agreements in 2014-16 are expected to consist of the following:

► Basin sales: Receive a basket price from sales to third-party marketers

► Rail: Receive Gulf, West and East Coast pricing less associated fees

► Enbridge: Receive Clearbrook, Minn., price less associated transportation fees

► Unit train rail options: WPX has up to 9,250 bbl/d of committed rail capacity until mid-2016, receiving West, East or Gulf Coast pricing less associated transportation fees


Sales Outlets Estimated Volume %

(Oct - Dec 2014)

Basin-Priced Sales 58%

Rail Deals 30%

Enbridge Capacity 12%

Total Sales Outlets 100%

San Juan Basin


Non-GAAP

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.


Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited)

2013 2014

(Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q Year 1Q 2Q 3Q 4Q YTD

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ (110) $ 14 $ (106) $ (876) $ (1,078) $ 1 $ (143) $ 57 $ (85)

Income (loss) from continuing operations – diluted earnings per share $(0.55) $ 0.07 $(0.53) $(4.36) $(5.38) $ 0.01 $ (0.71) $ 0.28 $ (0.42)

Pre-tax adjustments:

Impairment of producing properties, costs of acquired unproved reserves, leasehold and equity method investment (1) $ - $ - $ 19 $1,169 $1,188 $ - $ - $ - $ -

Impairments – exploratory related $ - $ - $ - $ - $ - $ - $ 40 $ 22 $ 62

Loss on sale of working interests in the Piceance Basin $ - $ - $ - $ - $ - $ - $ 195 $ 1 $ 196

Expense related to Early Exit Program $ - $ - $ - $ - $ - $ - $ 2 $ 8 $ 10

Early rig-release expenses $ - $ - $ - $ - $ - $ - $ - $ 6 $ 6

Costs related to chief executive officer separation $ - $ - $ - $ 4 $ 4 $ - $ - $ - $ -

Buyout of transportation agreement $ - $ - $ - $ 9 $ 9 $ - $ - $ - $ -

Unrealized MTM (gain) loss $ 103 $ (98) $ 13 $ 89 $ 107 $ 27 $ - $ (133) $ (106)

Total pre-tax adjustments $ 103 $ (98) $ 32 $1,271 $1,308 $ 27 $ 237 $ (96) $ 168

Less tax effect for above items $ (38) $ 36 $ (12) $ (463) $ (477) $ (10) $ (87) $ 35 $ (62)

Impact of new Argentine capital tax law (1) $ - $ - $ 6 $ - $ 6 $ - $ - $ - $ -

Impact of new state tax law in New York (net of federal benefit) $ - $ - $ - $ - $ - $ 9 $ - $ - $ 9

Total adjustments, after-tax $ 65 $ (62) $ 26 $ 808 $ 837 $ 26 $ 150 $ (61) $ 115

Adjusted income (loss) from continuing operations available to common stockholders $ (45) $ (48) $ (80) $ (68) $ (241) $ 27 $ 7 $ (4) $ 30

Adjusted diluted earnings (loss) per common share $(0.22) $(0.24) $(0.39) $(0.35) $(1.20) $ 0.13 $ 0.03 $(0.02) $ 0.14

Diluted weighted-average shares (millions) 199.9 203.8 200.7 200.9 200.4 205.2 202.7 207.5 202.5

(1) These items are presented net of amounts attributable to noncontrolling interests.


Reconciliation – EBITDAX (Unaudited)


2013 2014

(Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD

Adjusted EBITDAX

Reconciliation to net income (loss):

Net income (loss) $ (113) $ 22 $ (116) $ (984) $ (1,191)

$ 19 $ (133) $ 66 $ (48)

Interest expense 26 28 28 26 108

29 28 31 88

Provision (benefit) for income taxes (59) 9 (29) (514) (593)

15 (74) 28 (31)

Depreciation, depletion and amortization 217 215 230 230 892

203 211 213 627

Exploration expenses 18 20 21 371 430

15 57 29 101

EBITDAX 89 294 134 (871) (354)

281 89 367 737

Impairment of producing properties, costs of acquired unproved reserves and equity investments – – 19 864 883

– – – –

Loss on sale of working interests in the Piceance Basin – – – – –

– 195 1 196

Net (gain) loss on derivatives not designated as hedges 94 (78) 15 93 124

195 17 (148) 64

Net cash received (paid) related to settlement of derivatives not designated as hedges 9 (20) (2) (4) (17)

(168) (17) 15 (170)

(Income) loss from discontinued operations 6 (4) 8 97 107

(17) (8) (5) (30)

Adjusted EBITDAX $ 198 $ 192 $ 174 $ 179 $ 743

$ 291 $ 276 $ 230 $ 797

3rd quarter earnings call - amazon web services completions accelerating production and increasing...

Documents