2. Forward‐Looking Statements, Oil and Gas Reserves and Definitions
Forward‐Looking Statements
Certain statements contained herein that are not descriptions of historical facts are “forward‐looking” statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies,
actual results may differ materially from those expressed or implied by such forward‐looking statements. These risks, uncertainties and contingencies include, but are
not limited to, the following: the volatility of commodity prices for natural gas, NGLs and oil; our ability to develop, explore for and replace oil and gas reserves and
sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write‐
downs or write‐offs of our reserves or assets; the projected demand for and supply of natural gas, NGLs and oil; reductions in the borrowing base under our revolving
credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil
and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of
production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to
compete effectively against other independent and major oil and natural gas companies; our ability to successfully monetize select assets and repay our debt; leasehold
terms expiring before production can be established; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of
necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access
adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or
attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulation
or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic
and political conditions; and other risks set forth in our filings with the U.S. Securities and Exchange Commission (SEC).
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on
Form 10‐K for the year ended December 31, 2011. Readers should not place undue reliance on forward‐looking statements, which reflect management’s views only as
of the date hereof. We undertake no obligation to revise or update any forward‐looking statements, or to make any other forward‐looking statements, whether as a
result of new information, future events or otherwise.
Oil and Gas Reserves
Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves, but also “probable” reserves and
“possible” reserves. As noted above, 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 latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in
PVA’s Annual Report on Form 10‐K for the fiscal year ended December 31, 2011, which is available from PVA at Four Radnor Corporate Center, Suite 200, Radnor, PA
19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1‐800‐SEC‐0330 or from the SEC’s website at www.sec.gov.
Definitions
Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be
economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation
before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the
estimate is a deterministic estimate or probabilistic estimate. Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will equal or exceed the
proved plus probable reserve estimates). Possible reserves are those additional reserves that are less certain to be recoverable than probable reserves (there should be
at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus possible reserve estimates). “3P” reserves refer
to the sum of proved, probable and possible reserves. Estimated ultimate recovery (EUR) is the sum of reserves remaining as of a given date and cumulative production
as of that date.
2
3. PVA Overview
• Small‐cap domestic onshore E&P company
• Very active in the Eagle Ford Shale oil play with excellent results to date: YE11 PV‐10 of $278 MM
• HBP positions in Granite Wash, East Texas, Mississippi and Appalachia: YE11 PV‐10 of $596 MM
• Remain leveraged to natural gas prices
• PVA is executing a strategy of growth in oil and NGL rich plays
• 2010 and 2011 were transformational years, diversifying our portfolio towards oil / NGLs
• Successful drilling results in the Eagle Ford Shale – 47 wells on‐line (44 in Gonzales and 3 in Lavaca Counties)
• Adding to Eagle Ford drilling inventory – AMI in Lavaca County, exploration under way, encouraging results so far
• Strategy has resulted in excellent growth in EBITDAX and cash operating margins
• Focused on improving liquidity
• Have launched Mid‐Continent asset sale process
• Borrowing base of $300 MM following April 2012 redetermination – $180 MM of liquidity at 1Q12
• Have reduced capital spending in 2012 – 30% less than 2011
• Oil hedges: ~70% hedged for balance of 2012 at weighted average price of ~$100 per barrel
• Attractively valued
• 1.2x 2013 CFPS and 3.5x 2013 EBITDAX, 49% and 20% below peers
• $1.09 per Mcfe of YE11 proved reserves and roughly $8,100 per MMcfed of 1Q12 daily production
3
4. PVA’s Catalysts / Challenges
• Challenges
• Managing liquidity in light of our higher cost of capital
• Expansion of oily drilling inventory
• Very capital intensive industry
• Catalysts
• Eagle Ford exploratory success in Lavaca County, TX
• Strong Eagle Ford development drilling results
• Success in lowering Eagle Ford drilling and completion costs
• Increasing Eagle Ford production, margins and cash flows
• Granite Wash sale would increase liquidity and reduce leverage
• Retained Mid‐Continent oil prospect expected to be drilled and completed in 3Q12
• Attractive natural gas asset base that is primarily HBP
4
5. Options to Build Financial Liquidity
• Current liquidity is sufficient and anticipated to improve as 2012 progresses
• 2012 CAPEX outspend fully‐funded, largely discretionary; no material debt maturities until 2016
• Borrowing base equal to current commitment amount of $300 MM
• ~$180 MM of borrowing base liquidity at 3/31/12
• 2012E cash flow outspend of $107‐147 MM
• Granite Wash asset sale process underway
• Would reduce bank debt and increase liquidity going into 2013
• Liquids‐rich assets (approximately 50% liquids and oil)
• Significantly reduced capital expenditures
• 2012 capital program of $300‐325 MM is ~30% less than $446 MM in 2011
• 89% Eagle Ford (oily) ‐ no natural gas drilling due to weak prices
• Continue active hedging program
• Oil: ~70% hedged for balance of 2012 at average price of $100.47 per barrel
• Gas: ~25% hedged for balance of 2012 at average price of $5.27 per MMBtu
• 2013: 2,872 BOPD hedged at weighted average of $98.61 per barrel (floor/swap); no gas hedges
• 2014: 1,750 BOPD hedged at weighted average of $100.19 per barrel (floor/swap); no gas hedges
• Hedges help support borrowing base and strong cash flow margins
5
6. Business Strategy
• Commenced our “Gas‐to‐Oil” transition in mid‐2010
• Built Eagle Ford position from initial 6,800 net acres to nearly 25,000 net acres currently
– Up to approximately 250 well locations
– Includes acreage and locations expected to be earned in AMI in Lavaca County
• Grew oil/NGL production from 2,461 Bbls/day in 2Q10 to 8,387 Bbls/day in 1Q12 (+241%)
– Up 17% from 7,194 Bbls/day in 4Q11
– 42% of total production and 82% of product revenues
– Daily oil production alone grew 23% from 4Q11 to 1Q12
• Other oily / liquids‐rich plays include the Cotton Valley and other prospects
• Retain substantial core gas assets for eventual gas price recovery
• Haynesville Shale, Cotton Valley, Mississippi Selma Chalk and Marcellus Shale
• Make selective divestitures to improve operational focus and liquidity
• Have launched Granite Wash asset sale process
• Continue to expand oil and liquids reserves and drilling inventory
• Viola Lime oil prospect: ~10K net acres; will test in 2012; potential to expand
• MS Lime oil prospect: ~6K net acres; nearby production and testing looks encouraging
• Continue to grow oil and liquids production and cash flows
• Eagle Ford drilling emphasis in 2012
• Continued focus on optimizing drilling, completion and operating costs
6
7. Value Has Shifted to Oil
• In mid‐2010, PVA implemented a strategy to transition from dry gas to oil
• Since then, the decrease in gas prices and increase in oil & liquids prices has shifted the
market from a “6:1” to a “20:1” liquids‐to‐gas price environment (50:1 for oil)
• Examining revenue growth by commodity type reveals PVA’s true growth in value
Perception: “6‐to‐1” Equivalent Environment Reality: “20‐to‐1” Price Environment
Gas Producer With Little to No Production Growth Oil/NGL Producer With Revenue Growth
Pro Forma Production by Commodity Pro Forma Quarterly Revenue by Commodity
MMcfe per day (1 Bbl = 6 Mcfe) Pre‐Hedging; $MM
160 $90
120 $68
82%
~43%
80 $45
40 $23
~57%
18%
0 $0
Base Gas Shale Gas Oil NGLs Gas Oil NGLs
7
Note: Pro forma to exclude South Texas and South Louisiana assets sold in January 2010 and primarily Arkoma Basin assets sold in August 2011
8. EBITDAX and Cash Margin Growth
• EBITDAX has increased significantly since mid‐2010 when we shifted our strategy to oil
• Gross operating margin per Mcfe has also improved significantly due to the increase in
oil prices and declining operating costs per unit
• Eagle Ford margin was almost $15 per Mcfe in 1Q12
Quarterly EBITDAX and Cash Margins
$70 $7
$60 $6
$50 $5
$ per Mcfe
$ Millions
$40 $4
$30 $3
$20 $2
$10 $1
$0 $0
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12
Adjusted EBITDAX ($MM) Gross Operating Margin per Mcfe
8
Note: Gross operating margin per Mcfe is defined as total product revenues, excluding the impact of hedges, less direct operating expenses per unit of equivalent production
9. Asset Overview
Emerging Oil and Liquids‐Rich Plays Plus “Option” in Significant Gas Plays
2012E CAPEX: $300MM ‐ $325MM
~89% Eagle Ford / ~30% Less than 2011
2012E Production: 40.0‐43.0 Bcfe
~43% Oil & Liquids
2012E Production: 41.5 Bcfe
2011 Proved Reserves: 883 Bcfe
Oil / Liquids
Wet Gas
Dry Gas
9
Note: Based on 5/2/12 operational update; see Appendix
10. Eagle Ford Shale
The Most Economic Eagle Ford Shale Wells are in the Volatile Oil & Condensate Rich Gas Windows
Premier Shale Oil & Liquids Play Volatile Oil • 36,100 gross (≥24,900 net) acres in
Gonzales and Lavaca Counties, TX1
Condensate
Gonzales Rich Gas – Operator in Gonzales with 83% WI
– Operator in Lavaca with at least a 57%WI1
San Antonio – Avg. IP/30‐day rates of 1,001/645 BOEPD
Wilson Lavaca – Type curve EUR of ≥400 MBOE2
Bexar
– 88% oil, 6% NGLs and 6% gas, post processing
– 1Q12 D&C costs of $7.5MM per well
Atascosa
– Reduced proppant costs and stage sizes
Karnes DeWitt
– Initial Lavaca wells met/exceeded expectations
– Initial positive down‐spacing test of 3‐well pad
Victoria • Up to ~200 remaining drilling locations1
Goliad – 47 wells on line currently
– Includes AMI locations and down‐spaced
locations
McMullen Live Oak Bee Texas • Rigs, infrastructure in place
Acreage Valuations – Dedicated rigs and fracturing crew
Have Increased – Gas gathering and processing in place
Significantly in Recent
EFS Transactions
1 – Includes approximately ~6,800 net acres to be earned in the AMI in Lavaca Co.
10
2 – Internally generated type curve based on production history of wells drilled to date by PVA in Gonzales County; YE11 reserve report was
prepared by Wright & Company, Inc. and reflects a type curve EUR of 341 MBOE based on the production history of the wells through YE11
11. Eagle Ford Shale
Premier Acreage Position in Volatile Oil Window; Lavaca AMI Provides Additional Upside
PVA’s Eagle Ford Acreage
Volatile Oil Window Notable PVA Results
and Potential is Well‐ Gonzales
PVA Well Name IP Rates
Positioned Based on County Gardner 1H 1,247 BOEPD
Hawn Holt 9H 1,877 BOEPD
Overall Excellent MHR Hawn Holt 10H 1,188 BOEPD
Hawn Holt 11H 1,190 BOEPD
Industry Results in Area Hawn Holt 12H 1,495 BOEPD
Hawn Holt 13H 1,399 BOEPD
Hawn Holt 15H 1,298 BOEPD
Munson Ranch 1H 1,921 BOEPD
Munson Ranch 3H 1,538 BOEPD
Munson Ranch 4H 1,416 BOEPD
Munson Ranch 6H 1,808 BOEPD
Rock Creek Ranch 1H 1,257 BOEPD
Lavaca Schaefer 3H 1,129 BOEPD
Munson Ranch 5H 1,164 BOEPD
County D. Foreman 1H 1,202 BOEPD
Henning 1H 1,115 BOEPD
Rock Creek Ranch 5H 969 BOEPD
Rock Creek Ranch 6H 960 BOEPD
EOG Effenberger #1H (Lavaca) 922 BOEPD
Schacherl #1H (Lavaca) 1,277 BOEPD
PVA Acreage
PVA AMI with “Major”1
3‐D Seismic Survey
Notable PVA Results
Notable Industry Results
1 – Includes approximately ~6,800 net acres to be earned in the AMI in Lavaca Co. 11
Note: Wellhead rates (pre‐processing); production “windows” are PVA’s approximation
13. Eagle Ford Shale
Multi‐Year Inventory of Oily Locations
• Due to acreage acquisitions and leasing efforts over the past two years, we have
expanded our acreage position to approximately 36,100 gross (24,900 net) acres in the
volatile oil window
• We also have a multi‐year inventory of approximately 200 additional locations
• Successful down‐spacing testing has added ~120 locations to our inventory
• Locations will vary over time in terms of lateral length, frac stages, spacing and geology
• Unitizations with other industry participants and continued leasing is expected to yield additional locations
• Shiner acreage in Lavaca County will be earned with the drilling of three more wells by 3Q12
Producing Remaining Total Well Gross Net Acres /
Area Wells Locations Locations Acreage Acreage Location
Cortez 33 ~65 ~100 9,733 7,455 ~100
Cannonade 2 ~35 ~40 6,975 5,142 ~190
Rock Creek 8 ~15 ~25 2,200 1,833 ~95
SW Gonzales 1 ~10 ~10 2,199 2,199 ~200
Shiner 3 ~75 ~80 14,974 8,262 ~190
Totals 47 ~200 ~250 36,081 24,891 ~135
13
14. Eagle Ford Shale
Positive Trend: Volumes Up
• During 2011 and into early 2012, we have quickly ramped up the Eagle Ford Shale
• Approximately 95% of volumes are liquids, primarily crude oil
• Oil is sold into the Gulf Coast LLS market
2011‐12 Sales Volumes by Commodity
600
500
400
MBOE
300
200
100
0
1Q11 2Q11 3Q11 4Q11 1Q12
Net Oil Sales Net NGL Sales Net Gas Sales
14
15. Eagle Ford Shale
Positive Trend: Costs Down
• We have reduced our average well cost over time which, combined with strong oil prices,
has contributed to increased rates of return and margins
• The cost decline is due primarily to drilling efficiencies and altered completion design
• Spud‐to‐total depth (TD) and spud‐to‐sales averages of 19 and 46 days for non‐pilot holes
2011‐12 Drilling & Completion Costs
$12
$10
$8
$ Millions
$6
$4
$2
$0
3Q11 4Q11 1Q12
15
Average Total Well Cost Average Completion Cost
16. Gonzales County
Compelling Economics & Value at Varying Costs and Oil Prices
• Major assumptions
• ≥400 MBOE EUR type curve (~1,000 BOEPD IP rate, ~775 BOEPD 30‐day avg., 1.30 b factor)
• 100% WI / 75% NRI (25% royalty interest)
• Drilling and completion (D&C ) costs of $7.0 ‐ $8.0 MM
• Key takeaways
• BTAX PV‐10 of $4.0 ‐ $5.0 MM per well assuming a flat $85 per barrel NYMEX (WTI) oil price
• BTAX PV‐10 breakeven NYMEX oil pricing of $50 to $57 per barrel
Gonzales County Typical Well Economics
100
90 Assumes $4.00/MMBtu Flat Gas Price
80
Rate of Return BFIT ‐ %
70
60
$7.0 MM D&C Cost
50
40
$8.0 MM D&C Cost
30
20
10
0
$40 $50 $60 $70 $80 $90 $100 $110 $120
NYMEX Oil Price (Flat) ‐ $/Bbl 16
17. Lavaca County
Preliminary Economics & Value Look Excellent in Lavaca County
• Major assumptions
• ~500 MBOE EUR type curve (~1,100 BOEPD IP rate, ~850 BOEPD 30‐day avg., 1.26 b factor)
• 100% WI / 75% NRI (25% royalty interest)
• Drilling and completion (D&C ) costs of $8.5 ‐ $9.5 MM
• Key takeaways
• BTAX PV‐10 of $5.5 ‐ $6.5 MM per well assuming a flat $85 per barrel NYMEX (WTI) oil price
• BTAX PV‐10 breakeven NYMEX oil pricing of $49 to $54 per barrel
Lavaca County Preliminary Typical Well Economics
100
90 Assumes $4.00/MMBtu Flat Gas Price
80
Rate of Return BFIT ‐ %
70
60
$8.5 MM D&C Cost
50
40
$9.5 MM D&C Cost
30
20
10
0
$40 $50 $60 $70 $80 $90 $100 $110 $120
NYMEX Oil Price (Flat) ‐ $/Bbl 17
18. Comparison of Gonzales and Lavaca Counties
• Depth of Eagle Ford Shale
• Gonzales: 8,500 – 10,500 feet
• Lavaca: 11,000 – 12,000 feet
• Reservoir pressure
• Geo‐pressured
• Increases with depth moving from Gonzales to Lavaca
• Gas‐oil ratio (GOR)
• Consistent in both counties and within the “volatile oil” window
• Most likely attributable to the effect of the San Marcos Arch on the maturation window
• Gross thickness of the Eagle Ford comparable from Gonzales to Lavaca
• Average resistivity of the Eagle Ford decreases from west to east
• Increasing clay content
• Changes in petrophysical properties
18
19. Why PVA?
Investment Highlights
• Diversified and valuable portfolio of high‐quality assets
• Track record of low‐cost, high‐return operations
• Drilling and acquisitions focused on high return play types
• Successful transition from dry gas to oil and liquids underway
• Multi‐year inventory of economic drilling locations
• Retained optionality of natural gas assets
• Current liquidity is sufficient; focused on improving it during 2012
• Compelling value proposition
19
21. Crude Oil Hedges
Protecting our Capital Budget and Well Economics
• We have recently expanded our crude oil hedges given our increased oil drilling activity
• Our oil hedges thus far are equal to or greater than our forecasted oil price for 2012‐2013
Crude Oil Hedges1
Swaps and Collars
4,500 $110
Weighted Average Floor /
Weighted Avg. Floors and Swaps ($/Bbl.)
Swap Price by Quarter
4,000 $105
$101 $101 $100 $100 $100 $100
$100 $99 $99
3,500 $98 $98 $100
3,000 $95
Barrels per Day
Forecast Price by Quarter
2,500 $90
2,000 $85
1,500 $80
1,000 $75
500 $70
0 $65
2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14
21
1 – As of 5/2/12
22. Natural Gas Hedges
Protecting our Cash Flows During Depressed Gas Price Environment
• Our 2012 natural gas hedges have locked in prices well above the forecast
• Nevertheless, we are not drilling dry gas plays as the commodity remain oversupplied
Natural Gas Hedges1
Swaps and Collars
30 $6
Weighted Avg. Floors and Swaps ($/MMBtu)
Weighted Average Floor /
Swap Price by Quarter
24 $5.31 $5.31 $5
$5.10
MMBtu per Day (000s)
18 $4
Forecast Price by Quarter
12 $2.67 $3
$2.20
$2.00
6 $2
0 $1
2Q12 3Q12 4Q12
22
1 – As of 5/2/12
23. 2012 Guidance Table
As of May 2, 2012
1st Quarter Average Quarter for Full‐Year
Dollars in millions, except unit data 2012 Guidance
2012 2Q12 ‐ 4Q12
Production:
Natural gas (Bcf) 6.3 5.6 ‐ 6.0 23.0 ‐ 24.4
Crude oil (MBbls) 549 517 ‐ 575 2,100 ‐ 2,275
NGLs (MBbls) 215 173 ‐ 203 733 ‐ 825
Equivalent production (Bcfe) 10.9 9.7 ‐ 10.7 40.0 ‐ 43.0
Equivalent daily production (MMcfe per day) 119.5 105.9 116.8 109.3 ‐ 117.8
Equivalent production (MBOE) 1,812 1,618 ‐ 1,785 6,667 ‐ 7,167
Equivalent daily production (MBOE per day) 19.9 17.7 ‐ 19.5 18.2 ‐ 19.6
Percent crude oil and NGLs 42.1% 42.6% ‐ 43.6% 42.5% ‐ 43.3%
Production revenues:
Natural gas $ 14.9 10.4 ‐ 12.0 46.0 ‐ 51.0
Crude oil $ 58.7 51.8 ‐ 57.1 214.0 ‐ 230.0
NGLs $ 9.1 7.6 ‐ 8.6 32.0 ‐ 35.0
Total product revenues $ 82.7 69.8 ‐ 77.8 292.0 ‐ 316.0
Total product revenues ($ per Mcfe) $ 7.60 7.19 ‐ 7.26 7.30 ‐ 7.35
Total product revenues ($ per BOE) $ 45.62 43.12 ‐ 43.58 43.80 ‐ 44.09
Percent crude oil and NGLs 82.0% 84.5% ‐ 85.1% 82.5% ‐ 85.4%
Operating expenses:
Lease operating ($ per Mcfe) $ 0.84 0.80 ‐ 0.85
Lease operating ($ per BOE) $ 5.04 4.80 ‐ 5.10
Gathering, processing and transportation costs ($ per Mcfe) $ 0.38 0.31 ‐ 0.36
Gathering, processing and transportation costs ($ per BOE) $ 2.29 1.86 ‐ 2.16
Production and ad valorem taxes (percent of oil and gas revenues) 4.3% 4.0% ‐ 4.5%
General and administrative:
Recurring general and administrative $ 10.5 9.5 ‐ 10.2 39.0 ‐ 41.0
Share‐based compensation $ 1.6 1.6 ‐ 1.8 6.5 ‐ 7.0
Total reported G&A $ 12.1 11.1 ‐ 12.0 45.5 ‐ 48.0
Exploration expense $ 8.0 11.7 ‐ 12.7 43.0 ‐ 46.0
Unproved property amortization $ 8.2 8.9 ‐ 9.3 35.0 ‐ 36.0
Depreciation, depletion and amortization ($ per Mcfe) $ 4.67 4.75 ‐ 5.00
Depreciation, depletion and amortization ($ per BOE) $ 28.04 28.50 ‐ 30.00
Adjusted EBITDAX $ 64.2 51.9 ‐ 58.6 220.0 ‐ 240.0
Net cash provided by operating activities $ 70.7 38.1 ‐ 44.8 185.0 ‐ 205.0
Capital expenditures:
Drilling and completion $ 82.6 60.8 ‐ 64.1 265.0 ‐ 275.0
Pipeline, gathering, facilities $ 3.9 2.0 ‐ 3.7 10.0 ‐ 15.0
Seismic $ (0.4) 1.8 ‐ 3.5 5.0 ‐ 10.0
Lease acquisitions, field projects and other $ 4.3 5.2 ‐ 6.9 20.0 ‐ 25.0 23
Total oil and gas capital expenditures $ 90.4 69.9 ‐ 78.2 300.0 ‐ 325.0
24. Non‐GAAP Reconciliation
Adjusted EBITDAX
Year ended December 31, LTM 3 Mos. Ended
2007 2008 2009 2010 2011 1Q12 Mar‐11 Mar‐12
Adjusted EBITDAX dollars in millions
Net income (loss) from continuing operations $ 26.5 $ 93.6 $ (130.9) $ (65.3) $ (132.9) $ (118.5) $ (26.3) $ (11.9)
Add: Income tax expense (benefit) 30.5 55.6 (85.9) (42.9) (88.2) (80.6) (14.2) (6.6)
Add: Interest expense 20.1 24.6 44.2 53.7 56.2 57.5 13.5 14.8
Add: Depreciation, depletion and amortization 88.0 135.7 154.4 134.7 162.5 178.5 34.8 50.8
Add: Exploration 28.6 42.4 57.8 49.6 78.9 57.4 29.5 8.0
Add: Share‐based compensation expense 1.6 6.0 9.1 7.8 7.4 7.2 1.8 1.6
Add/Less: Derivatives (income) expense included in net income 2.0 (29.7) (31.6) (41.9) (15.7) (14.0) (1.3) 0.3
Add/Less: Cash receipts (payments) to settle derivatives 14.1 29.7 (5.8) 68.5 27.4 28.6 6.7 8.0
Add: Impairments 2.6 20.0 106.4 46.0 104.7 104.7 ‐ ‐
Add/Less: Net loss (gain) on sale of assets, other (12.6) (33.2) (2.0) (1.2) 19.1 18.8 (0.5) (0.8)
Adjusted EBITDAX $ 201.5 $ 344.7 $ 115.7 $ 209.0 $ 219.5 $ 239.7 $ 44.1 $ 64.2
24
