1Q 2015 Results - wpx-extranet-media.s3. · PDF fileNYMEX – Nat. Gas (Mcf) ($0.40) - ($0.60) ($0.40) - ... WPX Energy 1Q 2015 Results | May 6, 2015 16 DRY GAS WET GAS OIL 1 Acreage

1Q 2015 Results Rick Muncrief, President and Chief Executive Officer

May 6, 2015

Building the Premier Western Energy Producer

Strong production growth1

► Pro forma production grew 13%2

► Oil production of 34.6 Mbbl/d grew 79%

► Increasing full-year oil production by 4%

► Closed ~$600MM in transactions in 1Q ’15

► Apco Oil & Gas

► NE Pennsylvania acreage/transport

► Announced $200MM+ sale of NE supply link

WPX Energy 1Q 2015 Results | May 6, 2015

► Adjusted EBITDAX is flat despite ~50% decline in commodity prices1,3

Strong financial performance

Executing on divestitures

Costs trending lower

► Drilling and completion

► Lease operating expense

► Gathering, processing and transportation

► General and administrative

2

~217,000 NET ACRES ~3,900 DRILLABLE LOCATIONS

~200,000 NET ACRES ~11,500 DRILLABLE LOCATIONS

~87,000 NET ACRES ~610 DRILLABLE LOCATIONS

1 1Q ’15 vs. 1Q ’14 2 Production normalized for asset sales 3 Excluding the impact of net gas management margin including derivatives

CEO Perspective Over the Past Twelve Months

Positioning Organization for Success

□ Realigned organization □ Right sized staffing level □ Established a winning culture □ Attracting top talent

Announced or Completed $1.5B of Transactions

✓ ✓ ✓

Building Stronger Balance Sheet

□ Renegotiated revolver □ Issued $500MM debt offering □ Costs trending lower □ Executed strong hedges for 2015-16

✓ ✓

□ Monetized Piceance working interest to an MLP □ Executed Trail Ridge drilling carry □ Added San Juan Gallup acreage □ Monetized transport/acreage in NE PA □ Monetized international assets (Apco) □ Monetized firm New York transport □ Marketing Powder River basin □ Marketing remaining Marcellus acreage

✓

✓ TRANSACTIONAL

FINANCIAL

ORGANIZATIONAL

✓

✓

3 WPX Energy 1Q 2015 Results | May 6, 2015

✓

✓ ✓ ✓ ✓

✓

✓

Operational Results Clay Gaspar, Sr. VP Operations and Resource Development

WPX Continuing to Reduce Costs

5

Current Estimated Drilling and Completion Cost Versus Average Well Cost in 2014

G&A per BOE1

7% Improvement 17% Improvement 17% Improvement

LOE per BOE


1 Excludes severance and relocation costs

$3.60

$3.70

$3.80

$3.90

$4.00

1Q 2014 1Q 2015

$0.26 Decrease

$3.60

$4.20

$4.80

$5.40

$6.00

1Q 2014 1Q 2015

$1.01 Decrease

GP&T per BOE

$3.00

$3.30

$3.60

$3.90

$4.20

$4.50

1Q2014 1Q2015

$0.74 Decrease

-24%

-31%

-13%

-25%

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

Drilling Completion Facilities/Other Overall

0

5

10

15

20

25

30

35

40

45

1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q2015

Mb

oe

/d

Williston and San Juan Gallup Quarterly Production Growth


San Juan Gallup Williston

6

Williston Basin: Strong Production Growth and Cost Declining

► 1Q ’15 production growth of 60%1

► Reduced LOE by ~30%1

► Currently 15 drilled uncompleted wells

► Entered rail deal to achieve Brent pricing exposure

► ~$8.5MM D&C cost, 29% decrease vs. 2014 avg.

► Turning the operational focus back to completion optimization

WPX Energy 1Q 2015 Results | May 6, 2015 7

Source: RBC Capital Markets Bakken heat map, December 2014

WPX’s Acreage Window

D&C Reductions Versus 2014

-29% -30%

-25%

-29%

-35%

-25%

-15%

-5%


$10.56

$7.43

$0

$2

$4

$6

$8

$10

$12

1Q ’14 1Q ’15

$/B

OE

30% Decrease

LOE per BOE

11Q ’15 vs. 1Q ’14

San Juan Gallup: Continued Growth and Execution

► 1Q’15 production growth of 536%1

► Record 8-day spud-to-rig release

► Continued expansion of our gathering system

► Improving netbacks WTI less $8 - 10 per barrel

► ~$4.2MM D&C cost, 24% decrease vs. 2014 avg.

► Pursuing upside potential to well and completion design


DRY GAS

WET GAS

OIL

11Q ’15 vs. 1Q ’14

$7.84

$4.34

$0

$2

$4

$6

$8

1Q'14 1Q'15

45% Decrease

LOE per BOE

$/B

OE


-13%

-31%

-13%

-24%

-35%

-25%

-15%

-5%


Piceance: Large-Scale Resource with Deep Potential

► Pro forma 1Q ’15 production growth of 2%1

► 15% decrease in D&C cost for Valley and Ryan Gulch

► Average price differentials improved $0.54/Mcfe

► Two new Niobrara wells each posting IP rate above 10 MMcf/d



LOE per Mcfe

1 Normalized for impact of Legacy/G2X

CO

-11%

-31%

-15%

-35%

-25%

-15%

-5%

Drilling Completion Overall

$0.44

$0.39

$0.36

$0.38

$0.40

$0.42

$0.44

1Q'14 1Q'15

$/M

CFE

11% Decrease

Financial Results Kevin Vann, Chief Financial Officer

1st-Quarter and Annual Results


1Excluding Capex accrued in prior year and paid for in current year. Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.

11

1Q

Dollars in millions, except production numbers 2015 2014

Daily Production

Gas (MMcf/d) 705 795

Oil (Mbbl/d) 34.6 19.3

NGLs (Mbbl/d) 16.9 17.6

Equivalent (Mboe/d) 169.1 169.4

Adjusted EBITDAX $252 $277

Adjusted Net Income from Continuing Operations $19 $26

Capital Activity1 $297 $372

Production Prior Guidance Current Guidance

Natural Gas MMcf/d 615 - 650 630 - 665

Oil Mbbl/d 29.1 - 30.3 30.4 - 31.6

NGL Mbbl/d1 14.7 - 15.3 16.5 - 17.5

Total Mboe/d 146 - 154 152 - 160

Expenses Prior Guidance Current Guidance

$ per boe

LOE $4.00 - $5.00 $3.75 - $4.75

DD&A 13.50 - 14.25 13.50 - 14.25

GP&T 5.00 - 5.75 4.75 - 5.25

Production Tax 1.25 - 1.75 1.25 - 1.75

$ in Millions

G&A6 $230 - $250 $215 - $235

Gas Management7 0 - 10 0 - 10

Exploration 50 - 60 50 - 60

Interest Expense 125 - 130 125 - 130

Equity (Earnings) Loss 0 - (5) 0 - (5) Avg. Price Differentials4 Prior Guidance Current Guidance

NYMEX – Nat. Gas (Mcf) ($0.40) - ($0.60) ($0.40) - ($0.60)

Oil – WTI per barrel ($10.00) - ($13.00) ($9.00) - ($12.00)

2015 Full-Year Guidance

Tax Rate Prior Guidance Current Guidance

Tax Provision 33% - 37% 33% - 37%

Net Realized Price5 Prior Guidance Current Guidance

NGL – % of WTI 30% - 35% 30% - 35%

Cap Ex ($ in Millions) Prior Guidance Current Guidance

Piceance $200 - $225 $180 - $205

Williston 200 - 225 200 - 225

San Juan 275 - 300 295 - 320

Other2 0 - 25 0 - 25

Total3 $675 - $775 $675 - $775


1 NGL guidance assumes only 15% ethane recovery. 2 Other includes expenditures for Other Basins, Land, Exploration and Corporate. 3 Excludes any potential acquisition capital 4 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments, such as fuel. 5 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 6 Excludes severance and relocation costs and includes stock compensation expenses of $30 - $40MM. 7 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. Includes impact of realized hedges on non-equity production.

Hedging Overview

13

Apr - Dec 2015 2016

Volume/Day Average Price Volume/Day Average Price

Natural Gas (MMBtu)

Fixed Price Swaps1 410,000 $4.05 280,000 3.81

Costless Collars 50,000 $4.00 - $4.50 – –

Natural Gas Basis (MMBtu)

NGPL Basis Swaps 17,500 ($0.18) – –

Rockies Basis Swaps 220,000 ($0.16) – –

San Juan Basis Swaps 100,000 ($0.11) – –

SoCal Basis Swaps 20,000 $0.18 – –

Crude Oil (bbl)

Fixed Price Swaps1 19,658 $94.84 7,000 $61.32

1 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.

As of 4/13/2015


Positioned for Success in 2015 and Beyond

14

Execution

Focus

Discipline

Opportunistic


Appendix

San Juan Overview

~217,000 net acres ► Oil window: ~85,000 acres1

► Gas window: ~134,000 acres

► Operating 2+ rigs in 2015

~3,900 total gross drilling locations2

► Oil window: ~4003

► Gas window: ~3,5002

Commodity mix ► Oil window

► Oil: 69%

► NGLs: 13%

► Gas: 18%

► Gas window ► Natural gas: 99%

► NGLs: 1%

Available sales outlets ► Oil: Local refining markets or rail (WTI, Brent)

► Gas: San Juan


DRY GAS

WET GAS

OIL

1 Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4600' laterals

Williston Overview

~87,000 net acres

► Operating 1+ rigs in 2015

600+ gross drilling locations

► 520 operated drilling locations

► 90 non-op locations

Commodity mix

► 87% oil

► 7% natural gas

► 6% NGLs

Available sales outlets

► Clearbrook, Minn. (WTI)

► Guernsey, Wyo. (WTI)

► Local refining markets

► Rail to all coastal markets (Brent, LLS, WTI)


N D

Piceance Overview

~200,000 net acres ► Operating 2+ rigs in 2015

~11,500 gross drilling locations

Commodity mix1

► 2% oil

► 77% natural gas

► 21% NGLs

Available sales outlets

► San Juan

► Rockies

► California

► MidCon

Unbooked deep resource potential

► Niobrara/Mancos: ~160,000 acres

► Dry gas


CO

1 Assumes full ethane recovery

2014-15 Reported Daily Production


2014 Avg 2015 Avg 1Q 2Q 3Q 4Q Total 1Q 2Q 3Q 4Q Total

Total Production

Gas (MMcf/d) 795 791 746 742 768 705 705

Oil (Mbbl/d) 19.3 23.7 25.8 32.3 25.3 34.6 34.6

NGLs (Mbbl/d) 17.6 17.9 17.1 15.9 17.1 16.9 16.9

Mboe/d 169.4 173.4 167.2 171.9 170.5 169.1 169.1

Note: Excludes discontinued operations (Powder River and International production)

19

Domestic Price Realization for 2015

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

1Q ’15 2Q ’15 3Q ’15 4Q ’15 1Q ’15 2Q ’15 3Q ’15 4Q ’15 1Q ’15 2Q ’15 3Q ’15 4Q ’15

Weighted-Average Sales Price $2.90 $38.34 $22.74

Revenue Adjustments1 $(.28) $(.70) $(7.34)

Hedge Impact – – –

Net Price2 $2.62 $37.64 $15.40

Realized Portion of Derivatives Not Designated as Hedges3 $1.05 $29.49 –

Net Price Including All Derivatives

$3.67 $67.13 $15.40

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 $(1.40). 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.


WPX Financial Profile

Capitalization Liquidity and Credit Metrics

1Q 2015

Cash and Equivalents $82

Total Long-Term Debt $2,000

Net Debt $1,918

Stockholders’ Equity $4,389

Total Capitalization $6,307

1Q 2015

Cash $82

Available Credit Facility Capacity $1,500

Total Liquidity $1,582

Net Debt / Book Capitalization 30%

Net Debt / LTM Adjusted EBITDAX1 2.04x

Net Debt / YE14 Proved Reserves ($/boe) $2.64

Net Debt / 1Q15 Avg. Daily Production ($/boe/d) $11,349

1 See Appendix for EBITDAX reconciliation


Debt Maturity

$400

$1,100

$500

$1,500

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

$M

M

Undrawn as of March 31, 2015

Unsecured Credit Facility

Unsecured Senior Notes



5.25%

6.00%

5.25%

-2.00

-1.50

-1.00

-0.50

0.00

0.50

2007 to 2010 2011 to Now 3 Yr Fwd 2007 to 2010 2011 to Now 3 Yr Fwd

Western Prices Have Increased Relative to Eastern Locations

($1.76)

($0.19) ($0.23)

$0.33

($0.96)

West Basis Strengthening1 East Basis Weakening2

$ p

er M

MB

tu

3 3

1 Northwest Wyoming/Rocky Mountain basis 2 Dominion South basis 3 3-year average strip price as of 4/27/2015

($0.37)


Strong Western Supply/Demand Fundamentals Through 2020


2.0 Bcf/d demand increase

through 2020

Northwest


through 2020

Southwest


through 2020

Mexico

Demand +2.0 Bcf/d

Demand +0.5

Bcf/d

Demand +3.0

Bcf/d

Rockies and

San Juan Basin

production

flat to declining

through 2020

23

Mexican Exports to Drive Western Demand Growth


W. Texas 3.1 Bcf/d

S. Texas 3.64 Bcf/d

Bentek Sourced Export Capacities

Costa Azul LNG Facility

Total Proposed Capacity

7.7 Bcf/d July 2014, El Paso announced 21 Year deal with Mexico’s CFE to provide up to 500 MMBtu/d of firm capacity from SJ basin to Mexico border beginning Nov. 2014.

North Baja 130 Mcf/d

Sempra and Pemex recently announced coordination for the potential development of LNG exports with assumed capacity of up to 1 Bcf/d.

Sept 2014, CFE outlines two pipe-line projects sourcing 2.5 Bcf/d from Waha, Texas, by 2017.

Colorado Interstate Gas Co El Paso Natural Gas Co Kern River Gas Transmission Co Northwest Pipeline Corp Questar Pipeline Co Transcolorado Gas Transmission Co Transwestern Pipeline Co

Arizona 812 MMcf/d

San Juan Gallup Gathering System Creates Takeaway Optionality

WPX Gathering System

► WPX’s San Juan gathering system is connected to Western’s system at Lybrook with two additional connections expected in 2015

► Built 95 miles of oil, natural gas and water lines in 2014

► Expect to build 90+ miles of gathering lines in 2015

System Expansions and Connections

► Western adding a pipeline connection at Lybrook for delivery to the Tex-New-Mex Pipeline

► Western adding 25,000 bbl/d of rail capacity

► Western has ~400,000 barrels of system storage

► Acreage dedication of production with wellhead netbacks expected to be in the range of WTI less $8 - $10 for the second half of 2015 and beyond


WPX CDP site

WPX constructed pipe

WPX planned pipe for 2015

Western Refining (oil pipe)

WPX leasehold

Western dedicated acreage

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)

2014 2015 (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 $ - $ (144) $ 46 $ 227 $ 129 $ 22 $ 22

Income (loss) from continuing operations - diluted earnings per share $ - $(0.71) $ 0.23 $ 1.10 $ 0.62 $ 0.11 $ 0.11

Pre-tax adjustments:

Impairment of producing properties, costs of acquired unproved reserves and leasehold (1) $ - $ - $ - $ 20 $ 20 $ - $ -

Impairments – exploratory related $ - $ 40 $ 22 $ 67 $ 129 $ - $ -

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

Gain on sale of assets $ - $ - $ - $ - $ - $ (69) $ (69)

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

Contract Termination and early rig-release expenses $ - $ - $ 6 $ 6 $ 12 $ 26 $ 26

Assignment of natural gas storage commitment $ - $ - $ - $ 14 $ 14 $ - $ -

Costs related to severance and relocation $ - $ - $ - $ - $ - $ 8 $ 8

Unrealized MTM (gain) loss $ 27 $ - $(133) $(453) $(559) $ 30 $ 30

Total pre-tax adjustments $ 27 $ 237 $ (96) $(346) $(178) $ (5) $ (5)

Less tax effect for above items $ (10) $ (87) $ 35 $ 126 $ 64 $ 2 $ 2

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

Total adjustments, after-tax $ 26 $ 150 $ (61) $(220) $(105) $ (3) $ (3)

Adjusted income (loss) from continuing operations available to common stockholders $ 26 $ 6 $ (15) $ 7 $ 24 $ 19 $ 19

Adjusted diluted earnings (loss) per common share $ 0.13 $ 0.03 $(0.07) $ 0.03 $ 0.12 $ 0.09 $ 0.09

Diluted weighted-average shares (millions) 205.2 202.7 207.5 206.3 206.3 205.9 205.9

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


Reconciliation – EBITDAX (Unaudited)


2014 2015 (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD

Adjusted EBITDAX

Reconciliation to net income (loss):

Net income (loss) $ 19 $ (133) $ 66 $ 219 $ 171 $ 68 $ 68

Interest expense 29 28 31 35 123 33 33

Provision (benefit) for income taxes 13 (82) 25 119 75 13 13

Depreciation, depletion and amortization 193 202 201 214 810 216 216

Exploration expenses 15 54 28 76 173 7 7

EBITDAX 269 69 351 663 1,352 337 337

Impairment of producing properties, costs of acquired unproved reserves and equity investments

– – – 20 20 – –

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

Gain on sale of assets – – – – – (69) (69)

Net (gain) loss on derivatives 195 17 (148) (498) (434) (105) (105)

Net cash received (paid) related to settlement of derivatives

(168) (17) 15 45 (125) 135 135

(Income) loss from discontinued operations (19) (11) (20) 8 (42) (45) (45)

Adjusted EBITDAX $ 277 $ 253 $ 199 $ 238 $ 967 $ 252 $ 252

29

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.


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.


Documents

1Q 2015 Results - wpx-extranet-media.s3. · PDF fileNYMEX – Nat. Gas (Mcf) ($0.40) - ($0.60) ($0.40) - ... WPX Energy 1Q 2015 Results | May 6, 2015 16 DRY GAS WET GAS OIL 1 Acreage