DENBURY INC - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - DENBURY INC	form8k.htm

Exhibit 99.1

DENBURY REPORTS THIRD QUARTER 2012 RESULTS

PLANO, TX – November 6, 2012 – Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced adjusted net income (a non-GAAP measure)(1) of $127 million for the third quarter of 2012, or $0.33 per diluted share, on quarterly revenues of $595 million. This compares to $148 million of adjusted net income, or $0.37 per diluted share, on revenues of $572 million for the prior year third quarter, and $138 million of adjusted net income, or $0.35 per diluted share, on revenues of $597 million for the second quarter of 2012(2). Third quarter of 2012 net income (a GAAP measure) was $85 million, or $0.22 per diluted share. This compares to net income of $276 million, or $0.68 per diluted share, for the prior year third quarter, and net income of $212 million, or $0.54 per diluted share, for the second quarter of 2012.

Adjusted cash flow from operations (a non-GAAP measure)(1) for the third quarter of 2012 was $350 million. This compares to $358 million of the same measure for the prior year third quarter, and $362 million for the second quarter of 2012(2). Net cash provided by operating activities (a GAAP measure) was $294 million for the third quarter of 2012, compared to $316 million of the same measure for the prior year third quarter, and $441 million for the second quarter of 2012.

Key highlights for the third quarter of 2012 include:

Announced Bakken transaction(3) with Exxon Mobil Corporation and its wholly owned subsidiary XTO Energy Inc., further sharpening strategic focus on enhanced oil recovery (“EOR”) with carbon dioxide (“CO2”), adding to inventory of oil fields that are well suited for CO2 EOR, and significantly improving liquidity.

·	Increased average total production to 72,776 barrels of oil equivalent (“BOE”) per day (“BOE/d”), 9% higher than 2011’s third quarter level and 1% higher than the second quarter 2012 level.

·	Increased average tertiary oil production from the most recently commenced floods at Hastings and Oyster Bayou to a combined 4,334 barrels of oil per day (“Bbls/d”), a 35% increase from the second quarter 2012 level.

·	Commenced final construction phase of the Greencore pipeline, Denbury’s first CO2 pipeline in the Rocky Mountain region, which is on schedule to begin deliveries of CO2 to the Bell Creek Field in Montana in early 2013.

·	Resumed share repurchase program, acquiring 4.6 million shares since announcing the Bakken transaction to bring total purchases under such program since October 2011 to 18.7 million shares or nearly 5% of shares outstanding at September 30, 2011, at an average cost of $14.47 per share.

(1) See accompanying Schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.

(2) The GAAP to non-GAAP reconciliations for the second quarter of 2012 are part of the Company’s second quarter 2012 earnings release which is an exhibit to its August 2, 2012 Form 8-K.

(3) Full description of the Bakken transaction is provided in the Company’s September 20, 2012 Form 8-K.

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Phil Rykhoek, Denbury’s President and CEO, commented, "Our 2012 production remains on track to be in the upper half of our estimated ranges and we expect to close our Bakken transaction around the end of November. The Bakken transaction will sharpen our focus on our highly profitable CO2 EOR strategy and provides us with two additional oil fields in close proximity to our existing infrastructure that are well suited for CO2 EOR. Our large inventory of CO2 EOR projects provides us with excellent visibility on relatively lower risk, long-term production growth, while our strong balance sheet and expected cash proceeds from the Bakken transaction give us a very high degree of financial flexibility. Tertiary production was little changed from prior quarter levels, as continued strong growth at our newest floods at Hastings and Oyster Bayou was offset by Hurricane Isaac-related production shut-ins at several of our fields. Although we experienced no significant damage from the storm, we did shut-in production at several of our Gulf Coast fields in preparation for the storm, which had a slight impact on our production results this quarter. Importantly, our tertiary oil production has resumed its growth in the fourth quarter as we estimate it averaged over 36,000 barrels per day in October, a 3.5% increase over our average third quarter tertiary production. Subsequent to announcing the Bakken transaction, we resumed our share repurchase program and have now bought back nearly 5% of our year-ago outstanding common shares under the $500 million program and still have nearly $230 million of remaining repurchases authorized. Repurchases to date under the program effectively improve our per share metrics by about 5%.”

Production

Third quarter of 2012 total production averaged 72,776 BOE/d with 93% of this production being oil. Production increased by 9% from the prior year period level and by 1% from the second quarter of 2012 level. The sequential increase was the result of gains in production from the Company’s Bakken area assets under contract to be sold offsetting minor declines in tertiary and conventional production. The year-ago increase was the result of gains in tertiary and Bakken production more than offsetting declines in conventional production and the net impact of asset sales and purchases.

Third quarter of 2012 production from tertiary operations averaged 34,786 Bbls/d, a 12% increase from the prior year third quarter level, and a 1% decrease from the second quarter of 2012 level. The year-over-year growth in tertiary production was driven by contributions from new floods at Oyster Bayou and Hastings fields and existing floods at Tinsley, Heidelberg, and Delhi fields, which more than offset the impact of hurricane-related production shut-ins. Production from the Company’s Bakken area assets averaged 16,651 BOE/d in the third quarter of 2012, a 59% increase from the prior year third quarter level, and an 8% increase from the second quarter of 2012 level. The rapid year-over-year growth in Bakken area production was a result of Denbury’s active drilling program in the region. The slight sequential decrease in tertiary oil production from the second quarter of 2012 to the third quarter of 2012 was principally due to hurricane-related production shut-ins in August.

Review of Financial Results

Denbury’s third quarter of 2012 oil and natural gas revenues, excluding the impact of derivative contracts, increased by 4% from revenues in the prior year third quarter, as higher production drove a 9% increase in revenues, while lower realized oil and natural gas prices caused a 5% decrease in revenues.

Denbury’s oil price differential (the difference between the average price at which the Company sold its production and the average NYMEX price) declined from the prior year third quarter level as the Light Louisiana Sweet ("LLS") index premium declined and Bakken differentials widened. Company-wide oil price differentials in the third quarter of 2012 were $0.80 per barrel (“Bbl”) above NYMEX prices, compared to $7.25 per Bbl above NYMEX in the prior year third quarter. The LLS premium decreased between the two periods resulting in an average premium of $10.61 per Bbl to NYMEX in the third quarter of 2012 for the Company’s Gulf Coast tertiary oil production, down from a $14.84 per Bbl premium in the prior year third quarter. Differentials for the Company’s Bakken area production averaged $16.34 per Bbl below NYMEX in the third quarter of 2012, significantly wider than the $5.66 per Bbl below NYMEX realized in the prior year third quarter. During the third quarter of 2012, the Company sold approximately 39% of its crude oil at prices based on the LLS index price, approximately 22% at prices partially tied to the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.

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Lease operating expenses decreased 10% on a per BOE basis to $19.49 per BOE in the third quarter of 2012 from $21.68 per BOE in the third quarter of 2011. The decrease from the prior year third quarter level was primarily due to increased production from the Company’s Bakken area assets and the sale of non-core Gulf Coast and Rocky Mountain properties during the first half of 2012 (which had relatively high operating costs per BOE). Tertiary operating expenses averaged $23.50 per Bbl in the third quarter of 2012 compared to $24.91 per Bbl in the prior year third quarter. The decrease in tertiary operating expenses between the periods was primarily the result of the 12% increase in tertiary production which more than offset the additional costs related to operating new tertiary floods at Oyster Bayou and Hastings fields.

General and administrative (“G&A”) expenses totaled $38 million, or $5.71 per BOE, in the third quarter of 2012, compared to $27 million, or $4.33 per BOE, in the prior year third quarter. The increase in G&A expense was primarily due to a higher headcount, which resulted in higher compensation and employee-related costs along with a lower bonus accrual in the prior year period.

Interest expense in the third quarter of 2012 was $38 million, little changed from the prior year third quarter level. The impact of a nearly $650 million increase in average debt outstanding from the third quarter of 2011 to the third quarter of 2012 was mostly offset by a reduction in average interest rate to 7% from 8.5% and a $2 million increase in capitalized interest.

Depletion, depreciation and amortization of oil and natural gas properties was $17.12 per BOE in the third quarter of 2012, compared to $14.91 per BOE in the prior year third quarter. The increase was primarily due to higher finding and development costs per barrel and upward revisions to estimated future development costs associated with the Company’s Bakken area assets.

Denbury recorded a pre-tax $68 million non-cash fair value loss in the third quarter of 2012 due to decreases in the fair value of its derivative contracts, compared to a pre-tax $206 million non-cash fair value gain in the prior year third quarter. Pre-tax realized gains on hedges were $6.3 million in the third quarter of 2012 compared to a $4.6 million gain in the prior year third quarter.

2012 Production Estimates and Capital Expenditures

As previously announced, the Company has entered into an agreement to sell its Bakken area assets in a transaction expected to close around the end of November. Not including the impact of the Bakken transaction, Denbury’s expected average 2012 production estimates are unchanged at the levels shown in the following table.

Operating Area		2012 Estimated Production (BOE/d)
Tertiary		33,000 – 36,000
Bakken		14,350 – 16,350
Other		22,000
Production sold		425
Total Production		69,775 – 74,775

The Company continues to expect tertiary and total production to be in the upper half of estimated ranges. This would represent an 11% to 16% increase in tertiary production from full-year 2011 levels. Assuming the Bakken transaction closes at the end of November, estimated annual Bakken area production would be reduced by approximately 1,400 BOE/d, or about 1/12th of the area’s estimated average daily production in the fourth quarter of 2012. However, given the expected production contribution from the properties to be received in the Bakken transaction, the estimated total production range indicated above would be reduced by approximately 1,100 BOE/d.

Denbury’s 2012 capital expenditure budget remains at $1.5 billion, approximately two-thirds of which is for tertiary projects, with the remainder for the Bakken. The budgeted amount excludes acquisitions, capitalized interest, and tertiary start-up costs and is net of estimated proceeds from equipment sale/leasebacks. Of the $1.5 billion budgeted, slightly less than three-quarters had been spent through the third quarter of 2012.

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Conference Call, Annual Analyst Meeting, and Conference Presentation

Denbury will host a conference call to review the results today, Tuesday, November 6, at 10:00 A.M. (Central). The dial-in number is 800.230.1096 in the United States, or 612.332.0725 internationally. Individuals who would like to participate should dial the appropriate dial-in number ten minutes before the scheduled start time and provide the confirmation number 260588 to the operator. A live audio webcast of the call will also be accessible in the ‘Investor Relations’ section of the Company’s website at www.denbury.com. The call will be archived on the website for at least 30 days and a telephonic replay will be accessible for one month after the call by dialing 800.475.6701 in the United States or 320.365.3844 internationally and entering confirmation number 260588.

Denbury will be holding its annual analyst meeting in Houston on Monday, November 12, 2012. The presentation is scheduled to begin at 1:00 P.M. (Central) and will be webcast. In addition, Phil Rykhoek will be presenting at the Bank of America Merrill Lynch 2012 Global Energy Conference on Tuesday, November 13, 2012 at 2:50 P.M. (Eastern) in Miami. A link to the webcast presentations will be available at the Company’s website at www.denbury.com. The replays and slide presentations will be available on the website for approximately 30 days thereafter.

Denbury Resources Inc. is a growing independent oil and natural gas company. The Company is the largest combined oil and natural gas operator in both Mississippi and Montana, owns the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and holds significant operating acreage in the Rocky Mountain and Gulf Coast regions. The Company's goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with its most significant emphasis relating to tertiary oil recovery operations. For more information about Denbury, please visit www.denbury.com.

# # #

This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties, estimated 2012 production and capital expenditures, and potential proceeds from pending asset sales and equipment sale/leasebacks and other risks and uncertainties detailed in the Company's filings with the Securities and Exchange Commission, including Denbury's most recent reports on Form 10-K and Form 10-Q. These risks and uncertainties are incorporated by this reference as though fully set forth herein. These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management's assumptions and the Company's future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met. Actual results may vary materially.

DENBURY CONTACTS:

Phil Rykhoek, President and CEO, 972.673.2000

Mark Allen, Senior Vice President and CFO, 972.673.2000

Jack Collins, Executive Director, Investor Relations, 972.673.2028

Financial and Statistical Data Tables and Reconciliation Schedules

Following are unaudited financial highlights for the comparative three and nine month periods ended September 30, 2012 and 2011. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.

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THREE MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and unit data)
(Unaudited)
			Three Months Ended
			September 30,		Percentage
			2012	2011	Change
Revenues and other income
	Oil sales		579,429	552,281		+	5%
	Natural gas sales		8,727	13,242		-	34%
	CO2 sales and transportation fees		7,160	6,541		+	9%
	Interest income and other income		5,055	4,441		+	14%
		Total revenues and other income	600,371	576,505		+	4%

Expenses
	Lease operating expenses		130,485	133,285		-	2%
	Marketing expenses		14,728	6,416		+	>100%
	CO2 discovery and operating expenses		1,176	1,250		-	6%
	Taxes other than income		40,012	36,180		+	11%
	General and administrative		38,198	26,613		+	44%
	Interest expense, net		37,827	37,617		+	1%
	Depletion, depreciation, and amortization		136,935	101,978		+	34%
	Derivatives expense (income)		61,631	(210,154)		+	>100%
		Total expenses	460,992	133,185		+	>100%

Income before income taxes			139,379	443,320		-	69%

Income tax provision (benefit)
	Current income taxes		4,342	(5,331)		+	>100%
	Deferred income taxes		49,670	172,981		-	71%

Net income			85,367	275,670		-	69%

Net income per common share:
	Basic		0.22	0.69		-	68%
	Diluted		0.22	0.68		-	68%

Weighted average common shares outstanding:
	Basic		387,512	399,040		-	3%
	Diluted		390,909	403,311		-	3%

Production (daily – net of royalties):
	Oil (barrels)		67,655	61,984		+	9%
	Gas (mcf)		30,724	29,079		+	6%
	BOE (6:1)		72,776	66,830		+	9%

Unit sales price (including derivative settlements):
	Oil (per barrel)		92.99	96.52		-	4%
	Gas (per mcf)		5.53	7.35		-	25%
	BOE (6:1)		88.77	92.72		-	4%

Unit sales price (excluding derivative settlements):
	Oil (per barrel)		93.09	96.85		-	4%
	Gas (per mcf)		3.09	4.95		-	38%
	BOE (6:1)		87.84	91.98		-	5%

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			Three Months Ended
			September 30,		Percentage
			2012	2011	Change

Derivative contracts
Cash receipt on settlements			6,269	4,570		+	37%
Non-cash fair value adjustments on commodity derivatives			(67,900)	205,584		-	>100%
	Total income (expense) from derivative contracts		(61,631)	210,154		-	>100%

Non-GAAP financial measure1 – adjusted net income
Net income (GAAP measure)			85,367	275,670		-	69%
Non-cash fair value adjustments on commodity derivatives (net of taxes)			42,098	(127,462)		+	>100%
	Adjusted net income (non-GAAP measure)		127,465	148,208		-	14%

Non-GAAP financial measure1 – adjusted cash flow from operations
Net income (GAAP measure)			85,367	275,670		-	69%
Adjustments to reconcile to cash flow from operations:
	Depletion, depreciation, and amortization		136,935	101,978		+	34%
	Deferred income taxes		49,670	172,981		-	71%
	Non-cash fair value adjustments on commodity derivatives		67,900	(205,584)		+	>100%
	Other		10,368	12,657		-	18%
Adjusted cash flow from operations (non-GAAP measure)			350,240	357,702		-	2%
	Net change in assets and liabilities relating to operations		(56,734)	(41,963)		+	35%
Cash flow from operations (GAAP measure)			293,506	315,739		-	7%

Oil and natural gas capital expenditures			274,610	269,655		+	2%
Acquisitions of oil and natural gas properties			1,270	1,809		-	30%
Cash paid in Riley Ridge acquisition			—	199,233		-	100%
CO2 capital expenditures			40,632	30,504		+	33%
Pipelines and plants capital expenditures			61,784	44,169		+	40%
Net proceeds from sales of properties and equipment			1,671	29,166		-	94%

BOE data (6:1)
	Oil and natural gas revenues		87.84	91.98		-	5%
	Gain on settlements of derivative contracts		0.93	0.74		+	26%
	Lease operating expenses		(19.49)	(21.68)		-	10%
	Production and ad valorem taxes		(5.59)	(5.51)		+	1%
	Marketing expenses, net of third party purchases		(1.52)	(1.04)		+	46%
		Production netback	62.17	64.49		-	4%
	CO2 sales, net of operating expenses		0.89	0.86		+	3%
	General and administrative expenses		(5.71)	(4.33)		+	32%
	Net cash interest expense and other income		(4.34)	(4.80)		-	10%
	Other		(0.70)	1.96		-	>100%
	Changes in assets and liabilities relating to operations		(8.47)	(6.83)		+	24%
		Cash flow from operations	43.84	51.35		-	15%

1	See "Non-GAAP Measures" at the end of this report.

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NINE MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and unit data)
(Unaudited)
			Nine Months Ended
			September 30,		Percentage
			2012	2011	Change
Revenues and other income
	Oil sales		1,790,326	1,621,047		+	10%
	Natural gas sales		23,472	41,767		-	44%
	CO2 sales and transportation fees		19,256	16,808		+	15%
	Interest income and other income		14,214	12,445		+	14%
		Total revenues and other income	1,847,268	1,692,067		+	9%

Expenses
	Lease operating expenses		392,960	383,167		+	3%
	Marketing expenses		37,776	17,989		+	>100%
	CO2 discovery and operating expenses		8,443	4,889		+	73%
	Taxes other than income		122,518	108,295		+	13%
	General and administrative		109,631	97,641		+	12%
	Interest expense, net		115,745	128,643		-	10%
	Depletion, depreciation, and amortization		390,119	299,067		+	30%
	Derivatives income		(32,203)	(212,308)		-	85%
	Loss on early extinguishment of debt		—	16,131		-	100%
	Impairment of assets		17,515	—			N/A
	Other expenses		23,272	4,377		+	>100%
		Total expenses	1,185,776	847,891		+	40%

Income before income taxes			661,492	844,176		-	22%

Income tax provision
	Current income taxes		33,834	5,849		+	>100%
	Deferred income taxes		216,959	317,601		-	32%

Net income			410,699	520,726		-	21%

Net income per common share:
	Basic		1.06	1.31		-	19%
	Diluted		1.05	1.29		-	19%

Weighted average common shares outstanding:
	Basic		387,015	398,371		-	3%
	Diluted		390,854	403,575		-	3%

Production (daily – net of royalties):
	Oil (barrels)		67,331	60,007		+	12%
	Gas (mcf)		29,318	30,736		-	5%
	BOE (6:1)		72,217	65,129		+	11%

Unit sales price (including derivative settlements):
	Oil (per barrel)		96.52	97.50		-	1%
	Gas (per mcf)		5.65	7.25		-	22%
	BOE (6:1)		92.29	93.25		-	1%

Unit sales price (excluding derivative settlements):
	Oil (per barrel)		97.04	98.95		-	2%
	Gas (per mcf)		2.92	4.98		-	41%
	BOE (6:1)		91.66	93.52		-	2%

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			Nine Months Ended
			September 30,		Percentage
			2012	2011	Change
Derivative contracts
Cash receipt (payment) on settlements			12,361	(4,784)		+	>100%
Non-cash fair value adjustments on commodity derivatives			19,842	217,092		-	91%
	Total income from derivative contracts		32,203	212,308		-	85%
Non-GAAP financial measure1 – adjusted net income
Net income (GAAP measure)			410,699	520,726		-	21%
Non-cash fair value adjustments on commodity derivatives (net of taxes)			(12,302)	(134,597)		-	91%
Impairment of assets (net of taxes)			10,859	—			N/A
Cumulative effect of equipment lease correction (net of taxes)			5,240	—			N/A
Contractual helium nonperformance payment (net of taxes)			4,960	—			N/A
CO2 exploration costs (net of taxes)			3,053	—			N/A
Allowance for collectability on outstanding loans (net of taxes)			2,283	—			N/A
Loss on sale of Vanguard common units (net of taxes)			1,945	—			N/A
Loss on early extinguishment of debt (net of taxes)			—	10,001		-	100%
Transaction and other costs related to the Encore merger (net of taxes)			—	2,714		-	100%
	Adjusted net income (non-GAAP measure)		426,737	398,844		+	7%
Non-GAAP financial measure1 – adjusted cash flow from operations
Net income (GAAP measure)			410,699	520,726		-	21%
Adjustments to reconcile to cash flow from operations:
	Depletion, depreciation, and amortization		390,119	299,067		+	30%
	Deferred income taxes		216,959	317,601		-	32%
	Non-cash fair value adjustments on commodity derivatives		(19,842)	(217,092)		-	91%
	Impairment of assets		17,515	—			N/A
	Cumulative effect of equipment lease correction		8,452	—			N/A
	Contractual helium nonperformance payment		8,000	—			N/A
	Allowance for collectability on outstanding loans		3,683	—			N/A
	Loss on sale of Vanguard common units		3,137	—			N/A
	Loss on early extinguishment of debt		—	16,131		-	100%
	Other		25,583	36,544		-	30%
Adjusted cash flow from operations (non-GAAP measure)			1,064,305	972,977		+	9%
	Net change in assets and liabilities relating to operations		(38,179)	(133,885)		-	71%
Cash flow from operations (GAAP measure)			1,026,126	839,092		+	22%

Oil and natural gas capital expenditures			848,618	741,256		+	14%
Acquisitions of oil and natural gas properties2			155,636	34,291		+	>100%
Cash paid in Riley Ridge acquisition			—	199,233		-	100%
CO2 capital expenditures			93,945	62,546		+	50%
Pipelines and plants capital expenditures			231,459	142,406		+	63%
Net proceeds from sales of properties and equipment2			33,973	47,598		-	29%
Cash and cash equivalents			24,034	24,363		-	1%
Total assets			11,105,946	9,886,933		+	12%
Total borrowings under bank credit facility and senior
	subordinated notes (principal only)		2,676,350	2,161,349		+	24%
Financing and capital leases			403,961	249,729		+	62%
	Total debt (principal only)		3,080,311	2,411,078		+	28%
Total stockholders' equity			5,219,220	4,935,772		+	6%

BOE data (6:1)
	Oil and natural gas revenues		91.66	93.52		-	2%
	Gain (loss) on settlements of derivative contracts		0.63	(0.27)		+	>100%
	Lease operating expenses		(19.86)	(21.55)		-	8%
	Production and ad valorem taxes		(5.80)	(5.75)		+	1%
	Marketing expenses, net of third party purchases		(1.48)	(1.01)		+	47%
		Production netback	65.15	64.94		+	0%
	CO2 sales, net of operating expenses		0.54	0.67		-	19%
	General and administrative expenses		(5.54)	(5.49)		+	1%
	Net cash interest expense and other income		(4.57)	(5.79)		-	21%
	Other		(1.79)	0.38		-	>100%
	Changes in assets and liabilities relating to operations		(1.93)	(7.52)		-	74%
		Cash flow from operations	51.86	47.19		+	10%

1	See "Non-GAAP Measures" at the end of this report.
2	For the nine months ended September 30, 2012, excludes $212.5 million of cash which was held by a qualified intermediary to support a like-kind exchange transaction.

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Non-GAAP Measures

Adjusted net income is a non-GAAP measure. This measure reflects net income without regard to the fair value adjustments on the Company’s derivative contracts (the sole adjustment in the third quarter of 2012 comparative adjusted measure), or other certain items that are generally non-cash and unusual or non-recurring in nature and are typically excluded by the investment community in preparing its published estimates. The Company believes that it is important to consider this measure separately as it is a better reflection of the ongoing comparable results of the Company, without regard to changes during the period in the market value of the Company’s derivative contracts or other typically excluded items.

Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flow from operations measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. The Company believes that it is important to consider this measure separately, as it believes it can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and so forth, without regard to whether the earned or incurred item was collected or paid during that period.

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