1Q'2016 Earnings Call - Amazon AWS

0 downloads 215 Views 2MB Size Report
22 hours ago - E. Mandan North & Hidasta North. • Produced 685,000+ BOE in 180 days (81% oil). Arikara pad results
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