EXHIBIT 99.1
For Information
Brent A. Collins
303-861-8140
FOR IMMEDIATE RELEASE
ST. MARY REPORTS RESULTS FOR FOURTH QUARTER OF 2008
AND PROVED RESERVES AS OF YEAR-END 2008
· | Record quarterly production of 30.0 BCFE exceeds guidance of 28.0 – 29.0 BCFE |
· | Reported GAAP net loss of ($126.0 million), or ($2.01) per diluted share; pre-tax non-cash impairments of $336.3 million had significant impact on earnings |
· | Adjusted net income of $27.1 million, or $0.43 per diluted share |
· | Proved reserves at year-end 2008 of 865.5 BCFE; lower year-end commodity price resulted in significant negative price revisions |
· | Drilling and acquisition activity, excluding revisions, replaced 174% of production in 2008 |
DENVER, February 23, 2009 – St. Mary Land & Exploration Company (NYSE: SM) today reports financial results from the fourth quarter of 2008 and provides a brief update of its financial condition. The Company also is reporting its proved and 3P reserves as of December 31, 2008.
FOURTH QUARTER 2008 RESULTS
St. Mary posted a net loss for the fourth quarter of 2008 of ($126.0) million, a loss of ($2.01) per diluted share. This compares to net income of $32.9 million or $0.51 per diluted share, for the same period in 2007. Adjusted net income for the quarter, which adjusts for significant non-recurring and unusual non-cash items, was $27.1 million or $0.43 per diluted share, versus $64.9 million or $1.00 per diluted share, for the fourth quarter of 2007. A summary of the adjustments made to arrive at adjusted net income is presented in the table below.
For the Three Months Ended December 31, | ||||||||||||
2008 | 2007 | |||||||||||
Weighted-average diluted share count (in millions) | 62.6 | 64.6 | ||||||||||
$ in millions | Per Diluted Share | $ in millions | Per Diluted Share | |||||||||
Reported Net Income (Loss) | $ | (126.0 | ) | $ | (2.01 | ) | $ | 32.9 | $ | 0.51 | ||
After-tax adjustments, assuming effective tax rate for respective period | ||||||||||||
Change in Net Profits Plan liability | $ | (52.8 | ) | $ | (0.84 | ) | $ | 28.5 | $ | 0.44 | ||
Unrealized derivative (gain) loss | (7.8 | ) | (0.13 | ) | 2.1 | 0.03 | ||||||
(Gain) loss on sale of proved properties | (6.2 | ) | (0.10 | ) | 0.2 | 0.00 | ||||||
Loss on insurance settlement | 0.5 | 0.01 | 0.7 | 0.01 | ||||||||
Adjusted net income, before non-cash impairments | $ | (192.5 | ) | $ | (3.07 | ) | $ | 64.4 | $ | 1.00 | ||
After-tax adjustments for non-cash impairments, assuming effective tax rate for respective period | ||||||||||||
Impairment of proved properties | $ | 190.7 | $ | 3.05 | $ | 0.0 | $ | 0.00 | ||||
Abandonment & impairment of unproved properties | 22.7 | 0.36 | 0.6 | 0.01 | ||||||||
Impairment of goodwill | 6.2 | 0.10 | 0.0 | 0.00 | ||||||||
Adjusted net income | $ | 27.1 | $ | 0.43 | $ | 64.9 | $ | 1.00 | ||||
NOTE: Totals may not add due to rounding |
Discretionary cash flow decreased to $163.3 million for the fourth quarter of 2008 from $177.8 million in the same period last year. Net cash provided by operating activities decreased to $110.1 million for the fourth quarter of 2008 from $156.8 million in the same period in 2007.
Adjusted net income and discretionary cash flow are non-GAAP financial measures – please refer to the respective reconciliation in the accompanying Financial Highlights section at the end of this release.
St. Mary reported record quarterly production of 30.0 BCFE which came in above the guidance range of 28.0 to 29.0 BCFE. Strong performance in the Mid-Continent region was the primary driver in exceeding production guidance for the quarter. Year over year, the Company grew reported production 5% from 28.5 BCFE in the fourth quarter of 2007. Adjusting for sales of non-strategic assets that took place in 2008, year over year production growth was 11%. The Company’s oil and gas production growth on retained properties year over year is being driven primarily by development of the Cotton Valley program in the ArkLaTex region, successful drilling in the Wolfberry tight
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oil program in West Texas, and the horizontal Woodford shale program in the Arkoma Basin.
Revenues for the quarter were $258.2 million compared to $275.2 million for the same period in 2007. Average realized prices, excluding hedging activities, were $5.30 per Mcf and $50.17 per barrel during the quarter. These prices were 25% and 41% lower, respectively, than the fourth quarter of 2007. Compared to recent history, the Company experienced wider price differentials during the fourth quarter of 2008. Average realized prices, inclusive of hedging activities, were $7.09 per Mcf and $55.63 per barrel in the fourth quarter of 2008, which is a decrease of 9% and 21%, respectively, from the same period a year ago. In the fourth quarter of 2008, the Company’s average equivalent price per MCFE, net of hedging, was $7.84 per MCFE, which is a decrease of 15% from the $9.18 per MCFE realized in the comparable period in 2007.
Lease operating expense increased 20%, or $0.27 per MCFE, between the fourth quarters of 2007 and 2008 to $1.59 per MCFE. This amount is slightly below the Company’s lease operating expense guidance range of $1.60 to $1.65 per MCFE. Recurring lease operating costs were up approximately 11% or $0.13 per MCFE year over year. This increase reflects the impact of stronger commodity prices and high levels of activity in the first half of 2008 on the operating cost structure of exploration and production companies. Sequentially, recurring lease operating expense declined 2% or $0.03 per MCFE in the fourth quarter of 2008 from the preceding quarter. St. Mary expects that there will be continuing downward pressure on recurring lease operating expense in 2009 as a result of lower commodity prices and decreased levels of industry activity. Workover expense for the quarter increased by approximately $2.6 million year over year, primarily as a result of optimization efforts in the Rocky Mountain region.
Transportation expense of $0.20 per MCFE in the fourth quarter of 2008 was below guidance of $0.21 to $0.26 per MCFE. The reported per unit expense was an increase from $0.13 per MCFE for the comparative period in 2007. The increase is being driven primarily by the change in asset composition, and the associated transportation arrangements, in the Gulf Coast and ArkLaTex regions where the Company’s development activities are taking place in areas with different transportation arrangements than what St. Mary has historically used.
Significant commodity price decreases for both oil and natural gas resulted in a 42% decrease in production taxes between the fourth quarters of 2008 and 2007. Production taxes for the fourth quarter were $0.39 per MCFE, which was below guidance of $0.46 to $0.51 per MCFE as a result of lower than forecasted commodity prices throughout the quarter.
General and administrative expense for the fourth quarter of 2008 was $0.41 per MCFE, representing a 23% decrease from the $0.53 per MCFE recognized in the comparable quarter a year ago. The decrease year over year relates to smaller payments to participants in the Net Profits Plan, which was affected by lower commodity prices
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realized in the fourth quarter of 2008. Offsetting a portion of these decreases were increases between the periods in costs associated with headcount, such as salary, benefits, and office space. Reported G&A for the fourth quarter of 2008 was below guidance of $0.78 to $0.83 per MCFE.
Depletion and depreciation expense increased to $3.18 per MCFE in the fourth quarter of 2008 from $2.27 per MCFE in the comparable period in 2007. Sequentially, DD&A increased 22% from $2.61 per MCFE in the third quarter of 2008. Guidance for DD&A in the fourth quarter was $2.75 to $2.95 per MCFE. The increase in DD&A in the fourth quarter of 2008 is the result of a decrease in the Company’s proved reserves. Commodity prices used to determine the proved reserves at year-end 2008 were significantly lower than those used in the prior year. Additionally, the price differentials on oil in the Rocky Mountain region were wider than what the Company has experienced historically, which further lowered the oil price used to determine proved reserves at year-end. As a result, St. Mary’s proved reserves decreased by approximately 20% year over year due primarily to downward pricing revisions. This decrease in reserves results in a smaller base to amortize the capitalized costs related to our producing properties and therefore results in a higher DD&A rate for the period.
St. Mary recognized $336.3 million before income taxes in non-cash impairments in the fourth quarter of 2008, compared to $870,000 in the same period in 2007. The largest part of this amount was the impairment of producing properties of $292.1 million. The largest individual component was an impairment of $154.0 million related to properties in South Texas targeting the Olmos shallow gas formation. Additionally, St. Mary recognized producing property impairments on properties in the Hanging Woman Basin coalbed methane project, in the Greater Green River Basin, and in the Gulf of Mexico. Significantly lower prices for oil and gas in effect at year-end played a large part in triggering these impairments on producing properties. St. Mary also recognized an impairment of non-producing leasehold costs of $34.8 million in the fourth quarter of 2008. The bulk of this impairment relates to value initially assigned to probable and possible drilling locations in South Texas related to the Olmos shallow gas assets purchased in 2007, as well as acreage value related to the Floyd shale. Lastly, the Company recognized an impairment of goodwill for $9.5 million associated with an acquisition made in 2005.
In fourth quarter of 2008, St. Mary recognized a pre-tax non-cash benefit of $80.9 million as a result of the decrease in the Net Profits Plan liability, which decreased during the quarter as a result of the significant decrease in forecasted oil and natural gas prices from September 30, 2008, to December 31, 2008. This liability is a significant management estimate and is highly sensitive to a number of assumptions including future commodity prices, production rates, and operating costs. The last pool created under this legacy compensation plan was in 2007.
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FINANCIAL POSITION AND LIQUIDITY
As of December 31, 2008, St. Mary had total long-term debt of $587.5 million, comprised of $287.5 million in 3.50% Senior Convertible Notes and $300.0 million drawn under the existing long-term credit facility. The Company’s debt-to-book capitalization ratio was 34% as of the end of the quarter. The long-term credit facility requires compliance with two financial covenants, consisting of a leverage to trailing EBITDA limit and a minimum modified current ratio multiple. St. Mary was in compliance with both covenants at quarter-end.
The borrowing base for the long-term credit facility was redetermined by St. Mary’s bank group on October 1, 2008, at an amount of $1.4 billion. The bank group is comprised of ten banks, led by Wells Fargo. The Company has elected a commitment amount of $500 million given its expected near term liquidity needs. The current credit facility is set to expire in April of 2010. St. Mary has been in discussions with banks both within and outside the existing bank group about replacing the existing credit facility and potentially increasing the commitment amount. The Company expects to have a new credit facility in place in the first half of 2009.
PROVED RESERVES
Below is a roll-forward of the Company’s proved reserves from year-end 2007 to year-end 2008.
(BCFE) | ||
Beginning of year | 1,086.5 | |
Production | (114.6 | ) |
Purchase of minerals in place | 29.1 | |
Sales of reserves | (61.4 | ) |
Discoveries and extensions | 45.1 | |
Infill reserves in an existing proved field | 125.0 | |
Performance revisions | (44.5 | ) |
Pricing revisions | (199.7 | ) |
End of year | 865.5 |
St. Mary’s proved reserves as of December 31, 2008, were 865.5 BCFE, which is a decrease of 20% from 1086.5 BCFE at the end of 2007. The reserves are comprised of 51.4 MMBbl of oil and 557.4 Bcf of natural gas, and are 83% proved developed. Over 80% of St. Mary’s proved reserves by value were either prepared or reviewed by outside reserve engineering firms. Prices used to determine the proved reserves decreased significantly from 2007 to 2008; SEC-mandated pricing in effect at December 31, 2008, was $5.71 per MMBtu and $44.60 per barrel, which are down 16% and 54%, respectively, from the $6.80 per MMBtu and $95.98 per barrel used on December 31, 2007. In addition to the drop in base commodity prices used for the calculation of 2008’s reserves, the Company was impacted by larger differentials for oil
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and natural gas liquids on this measurement date. In the Williston Basin in the Rocky Mountain region, where St. Mary has a significant legacy oil-dominated asset base, average oil differentials increased roughly from $7.00 per barrel to $15.00 per barrel as of year-end. In South Texas, the natural gas liquid fractionation spread shrank from $10.34 per MMBtu at year-end 2007 to $0.29 per MMBtu at year-end 2008.
Proved reserves were adversely impacted by negative pricing and performance revisions at year-end 2008. St. Mary’s negative price revision for the year was 199.7 BCFE, of which 74% related to proved developed reserves. Two-thirds of the 199.7 BCFE in negative price revisions related to the Company’s oil-weighted properties in the Rocky Mountain region, which bore the brunt of the reserve impact caused by a lower year-end oil price and a wider price differential. Lower year-end prices for natural gas liquids also led to a meaningful negative price revision on proved reserves in South Texas.
The SEC recently published new rules for reporting year-end reserves that will go into effect for the calendar year 2009. Pursuant to the new rules, prices to be used to calculate year-end reserves will be based on the average of the prices that were in effect on the first trading day of each calendar month of the year rather than on the price that was in effect on the last trading day of the year. The table below details the amount of reserves the Company would recapture at various pricing assumptions.
(in BCFE) | Year-end 2008 at year-end 2007 SEC pricing and differentials | Year-end 2008 under new SEC pricing & differentials methodology | ||
Assumed pricing | $95.98/bbl & $6.80 MMBtu | $102.06/bbl & $8.91 MMBtu | ||
Year-end 2008 SEC Proved Reserves | 865.5 | 865.5 | ||
Recaptured PDP reserves | 147.0 | 157.0 | ||
Recaptured PDN/PUD reserves | 38.0 | 42.0 | ||
Drilling adds | 35.0 | 35.0 | ||
Year-end 2008 at assumed pricing | 1,085.5 | 1,099.5 |
The largest component of the negative performance revision relates to Olmos shallow gas properties in South Texas that were acquired in 2007. Results from the Olmos development did not meet the Company’s expectations, and midway through 2008 development was stopped to conduct a technical review. While parts of the technical review are still underway, the initial results have cast doubt on the viability of Olmos development on the scale originally contemplated at the time these acquisitions were made. Compared to the Company’s original assumptions, the reservoir is more compartmentalized than initially expected and lower reserve outcomes have been realized while attempting to infill parts of the field. While results from the Olmos
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program have been disappointing, St. Mary’s activities targeting the deeper formations in the basin have been promising. The Company participated during the year in a joint venture with two other exploration and production companies that allows St. Mary to earn acreage in an area of the basin that is prospective for the Eagle Ford and Pearsall shale formations, both of which appear to have potential given recent industry activity.
3P RESERVES
St. Mary’s proved, probable, and possible (3P) reserves as of year-end 2008 were negatively impacted by the same pricing conditions referred to above for proved reserves. The following table provides the components of the Company’s 3P reserves as of year-end 2007 and 2008.
December 31, | ||||
2008 | 2007 | |||
(in BCFE) | ||||
Proved | 865.5 | 1,086.5 | ||
Probable | 587.8 | 835.9 | ||
Possible | 699.6 | 870.0 | ||
Total 3P | 2,152.9 | 2,792.5 |
Not included in the 3P reserves for 2008 above is any potential related to the Company’s exposure to three emerging resource plays – the Haynesville shale, the Eagle Ford shale, and the Marcellus shale. St. Mary has approximately 50,000, 210,000, and 43,000 net acres, respectively, in these shale plays assuming all the acreage is earned.
Proved reserves were evaluated using the parameters and pricing required by the SEC. Probable and possible reserves were evaluated using the parameters set forth by the Society of Petroleum Engineers.
EARNINGS CALL INFORMATION
The Company has scheduled a teleconference to discuss fourth quarter and full year 2008 results on February 24, 2009 at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The call participation number is 888-811-1227. An audio replay of the call will be available approximately two hours after the call at 800-642-1687, conference number 84161206. International participants can dial 706-679-9922 to take part in the conference call and can access a replay of the call at 706-645-9291, conference number 84161206. Replays can be accessed through March 20, 2009.
In addition, the call will be webcast live and can be accessed at St. Mary’s web site at www.stmaryland.com. An audio recording of the conference call will be available at that site through March 20, 2009.
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INFORMATION ABOUT FORWARD LOOKING STATEMENTS
This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “will,” “believe,” “budget,” “anticipate,” “plan,” “intend,” “estimate,” “forecast,” and “expect” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause St. Mary’s actual results to differ materially from results expressed or implied by the forward looking statements. These risks include such factors as the volatility and level of oil and natural gas prices, the uncertain nature of the expected benefits from the acquisition and divestiture of oil and gas properties, uncertainties inherent in projecting future rates of production from drilling activities and acquisitions, the ability of purchasers of production to pay for those sales, the availability of debt and equity financing, the ability of the banks in the Company’s credit facility to fund requested borrowings, the ability of hedge counterparties to settle hedges in favor of the Company, the imprecise nature of estimating oil and gas reserves, the availability of additional economically attractive exploration, development, and property acquisition opportunities for future growth and any necessary financings, unexpected drilling conditions and results, unsuccessful exploration and development drilling, drilling and operating service availability, the risks associated with the Company’s hedging strategy, and other such matters discussed in the “Risk Factors” section of St. Mary’s 2008 Annual Report on Form 10-K, which is expected to be filed on or around February 24, 2009. Although St. Mary may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by securities laws.
INFORMATION ABOUT RESERVES AND RESOURCES
The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. St. Mary uses in this press release the terms “probable”, “possible”, and “3P” reserves, which SEC guidelines prohibit from being included in filings with the SEC. Probable reserves are unproved reserves which are more likely than not to be recoverable. Possible reserves are unproved reserves which are less likely to be recoverable than probable reserves. Estimates of unproved reserves which may potentially be recoverable through additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, presenting the estimated impact of applying the 12-month-average pricing provisions of the oil and gas reserve reporting rules recently promulgated by the SEC or the reserves that would be recaptured at various price scenarios are strictly prohibited from being included in filings with the SEC. Lastly, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
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ST. MARY LAND & EXPLORATION COMPANY | ||||||||||||||||
FINANCIAL HIGHLIGHTS | ||||||||||||||||
December 31, 2008 | ||||||||||||||||
Production Data | For the Three Months | For the Years | ||||||||||||||
Ended December 31, | Ended December 31, | |||||||||||||||
2008 | 2007 | Percent Change | 2008 | 2007 | Percent Change | |||||||||||
Average realized sales price, before hedging: | ||||||||||||||||
Oil (per Bbl) | $ | 50.17 | $ | 84.63 | -41% | $ | 92.99 | $ | 67.56 | 38% | ||||||
Gas (per Mcf) | $ | 5.30 | $ | 7.07 | -25% | $ | 8.60 | $ | 6.74 | 28% | ||||||
Average realized sales price, net of hedging: | ||||||||||||||||
Oil (per Bbl) | $ | 55.63 | $ | 69.99 | -21% | $ | 75.59 | $ | 62.60 | 21% | ||||||
Gas (per Mcf) | $ | 7.09 | $ | 7.80 | -9% | $ | 8.79 | $ | 7.63 | 15% | ||||||
Production: | ||||||||||||||||
Oil (MMBbls) | 1.7 | 1.7 | 1% | 6.6 | 6.9 | -4% | ||||||||||
Gas (Bcf) | 19.7 | 18.3 | 7% | 74.9 | 66.1 | 13% | ||||||||||
BCFE (6:1) | 30.0 | 28.5 | 5% | 114.6 | 107.5 | 7% | ||||||||||
Daily production: | ||||||||||||||||
Oil (MBbls per day) | 18.7 | 18.5 | 1% | 18.1 | 18.9 | -4% | ||||||||||
Gas (MMcf per day) | 213.8 | 199.1 | 7% | 204.7 | 181.0 | 13% | ||||||||||
MMCFE per day (6:1) | 326.0 | 310.2 | 5% | 313.1 | 294.5 | 6% | ||||||||||
Margin analysis per MCFE: | ||||||||||||||||
Average realized sales price, before hedging | $ | 6.35 | $ | 9.59 | -34% | $ | 10.99 | $ | 8.48 | 30% | ||||||
Average realized sales price, net of hedging | $ | 7.84 | $ | 9.18 | -15% | $ | 10.11 | $ | 8.71 | 16% | ||||||
Lease operating expense | $ | 1.59 | $ | 1.32 | 20% | 1.46 | 1.31 | 11% | ||||||||
Transportation | $ | 0.20 | $ | 0.13 | 54% | 0.19 | 0.14 | 36% | ||||||||
Production taxes | $ | 0.39 | $ | 0.67 | -42% | 0.71 | 0.58 | 22% | ||||||||
General and administrative | $ | 0.41 | $ | 0.53 | -23% | 0.69 | 0.56 | 23% | ||||||||
Operating margin | $ | 5.25 | $ | 6.53 | -20% | $ | 7.06 | $ | 6.12 | 15% | ||||||
Depletion, depreciation, amortization, and | ||||||||||||||||
asset retirement obligation liability accretion | $ | 3.18 | $ | 2.27 | 40% | $ | 2.74 | $ | 2.12 | 29% |
ST. MARY LAND & EXPLORATION COMPANY | ||||||||||||
FINANCIAL HIGHLIGHTS | ||||||||||||
December 31, 2008 | ||||||||||||
Consolidated Statements of Operations | ||||||||||||
(In thousands, except per share amounts) | For the Three Months | For the Year | ||||||||||
Ended December 31, | Ended December 31, | |||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||
Operating revenues and other income: | ||||||||||||
Oil and gas production revenue | $ | 190,499 | $ | 273,736 | $ | 1,259,400 | $ | 912,093 | ||||
Realized oil and gas hedge gain (loss) | 44,741 | (11,676 | ) | (101,096 | ) | 24,484 | ||||||
Marketed gas system revenue | 11,935 | 13,909 | 77,350 | 45,149 | ||||||||
Gain (loss) on sale of proved properties | 9,494 | (367 | ) | 63,557 | (367 | ) | ||||||
Other revenue | 1,500 | (355 | ) | 2,090 | 8,735 | |||||||
Total operating revenues and other income | 258,169 | 275,247 | 1,301,301 | 990,094 | ||||||||
Operating expenses: | ||||||||||||
Oil and gas production expense | 65,530 | 60,590 | 271,355 | 218,208 | ||||||||
Depletion, depreciation, amortization, | ||||||||||||
and asset retirement obligation liability accretion | 95,260 | 64,919 | 314,330 | 227,596 | ||||||||
Exploration | 17,743 | 16,030 | 60,121 | 58,686 | ||||||||
Impairment of proved properties | 292,100 | - | 302,230 | - | ||||||||
Abandonment and impairment of unproved properties | 34,754 | 870 | 39,049 | 4,756 | ||||||||
Impairment of goodwill | 9,452 | - | 9,452 | - | ||||||||
General and administrative | 12,354 | 15,187 | 79,503 | 60,149 | ||||||||
Bad debt expense | 143 | - | 16,735 | - | ||||||||
Change in Net Profits Plan liability | (80,941 | ) | 43,875 | (34,040 | ) | 50,823 | ||||||
Marketed gas system expense | 11,241 | 13,031 | 72,159 | 42,485 | ||||||||
Unrealized derivative (gain) loss | (12,011 | ) | 3,234 | (11,209 | ) | 5,458 | ||||||
Other expense | 1,260 | 946 | 10,415 | 2,522 | ||||||||
Total operating expenses | 446,885 | 218,682 | 1,130,100 | 670,683 | ||||||||
Income (loss) from operations | (188,716 | ) | 56,565 | 171,201 | 319,411 | |||||||
Nonoperating income (expense): | ||||||||||||
Interest income | 90 | 134 | 485 | 746 | ||||||||
Interest expense | (4,417 | ) | (6,010 | ) | (20,275 | ) | (19,895 | ) | ||||
Income (loss) before income taxes | (193,043 | ) | 50,689 | 151,411 | 300,262 | |||||||
Income tax (expense) benefit | 67,003 | (17,815 | ) | (59,858 | ) | (110,550 | ) | |||||
Net income (loss) | $ | (126,040 | ) | $ | 32,874 | $ | 91,553 | $ | 189,712 | |||
Basic weighted-average common shares outstanding | 62,212 | 63,300 | 62,243 | 61,852 | ||||||||
Diluted weighted-average common shares outstanding | 62,630 | 64,635 | 63,133 | 64,850 | ||||||||
Basic net income (loss) per common share | $ | (2.03 | ) | $ | 0.52 | $ | 1.47 | $ | 3.07 | |||
Diluted net income (loss) per common share | $ | (2.01 | ) | $ | 0.51 | $ | 1.45 | $ | 2.94 |
ST. MARY LAND & EXPLORATION COMPANY | ||||||
FINANCIAL HIGHLIGHTS | ||||||
December 31, 2008 | ||||||
Consolidated Balance Sheets | ||||||
(In thousands, except share amounts) | December 31, | December 31, | ||||
ASSETS | 2008 | 2007 | ||||
Current assets: | ||||||
Cash and cash equivalents | $ | 6,131 | $ | 43,510 | ||
Short-term investments | 1,002 | 1,173 | ||||
Accounts receivable, net of allowance for doubtful accounts | ||||||
of $16,788 in 2008 and $152 in 2007 | 157,690 | 159,149 | ||||
Refundable income taxes | 13,161 | 933 | ||||
Prepaid expenses and other | 22,161 | 14,129 | ||||
Accrued derivative asset | 111,649 | 17,836 | ||||
Deferred income taxes | - | 33,211 | ||||
Total current assets | 311,794 | 269,941 | ||||
Property and equipment (successful efforts method), at cost: | ||||||
Land | 1,350 | - | ||||
Proved oil and gas properties | 3,007,946 | 2,721,229 | ||||
Less - accumulated depletion, depreciation, and amortization | (947,207 | ) | (804,785 | ) | ||
Unproved oil and gas properties, net of impairment allowance | ||||||
of $42,945 in 2008 and $10,319 in 2007 | 168,817 | 134,386 | ||||
Wells in progress | 90,910 | 137,417 | ||||
Oil and gas properties held for sale less accumulated depletion, | ||||||
depreciation, and amortization | 1,827 | 76,921 | ||||
Other property and equipment, net of accumulated depreciation | ||||||
of $13,848 in 2008 and $11,549 in 2007 | 13,458 | 9,230 | ||||
2,337,101 | 2,274,398 | |||||
Other noncurrent assets: | ||||||
Goodwill | - | 9,452 | ||||
Accrued derivative asset | 21,541 | 5,483 | ||||
Restricted cash subject to Section 1031 Exchange | 14,398 | - | ||||
Other noncurrent assets | 10,182 | 12,406 | ||||
Total other noncurrent assets | 46,121 | 27,341 | ||||
Total Assets | $ | 2,695,016 | $ | 2,571,680 | ||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable and accrued expenses | $ | 254,811 | $ | 254,918 | ||
Accrued derivative liability | 501 | 97,627 | ||||
Deposit associated with oil and gas properties held for sale | - | 10,000 | ||||
Deferred income taxes | 41,289 | - | ||||
Total current liabilities | 296,601 | 362,545 | ||||
Noncurrent liabilities: | ||||||
Long-term credit facility | 300,000 | 285,000 | ||||
Senior convertible notes | 287,500 | 287,500 | ||||
Asset retirement obligation | 108,755 | 96,432 | ||||
Asset retirement obligation associated with oil and gas | ||||||
properties held for sale | 238 | 8,744 | ||||
Net Profits Plan liability | 177,366 | 211,406 | ||||
Deferred income taxes | 358,334 | 257,603 | ||||
Accrued derivative liability | 27,419 | 190,262 | ||||
Other noncurrent liabilities | 11,318 | 8,843 | ||||
Total noncurrent liabilities | 1,270,930 | 1,345,790 | ||||
Stockholders' equity: | ||||||
Common stock, $0.01 par value: authorized - 200,000,000 shares; | ||||||
issued: 62,465,572 shares in 2008 and 64,010,832 shares | ||||||
in 2007; outstanding, net of treasury shares: 62,288,585 shares | ||||||
in 2008 and 63,001,120 shares in 2007 | 625 | 640 | ||||
Additional paid-in capital | 99,440 | 170,070 | ||||
Treasury stock, at cost: 176,987 shares in 2008 and 1,009,712 | ||||||
shares in 2007 | (1,892 | ) | (29,049 | ) | ||
Retained earnings | 964,019 | 878,652 | ||||
Accumulated other comprehensive loss | 65,293 | (156,968 | ) | |||
Total stockholders' equity | 1,127,485 | 863,345 | ||||
Total Liabilities and Stockholders' Equity | $ | 2,695,016 | $ | 2,571,680 |
ST. MARY LAND & EXPLORATION COMPANY | ||||||||||||
FINANCIAL HIGHLIGHTS | ||||||||||||
December 31, 2008 | ||||||||||||
Consolidated Statements of Cash Flows | ||||||||||||
(In thousands) | For the Three Months | For the Years | ||||||||||
Ended December 31, | Ended December 31, | |||||||||||
Cash flows from operating activities: | 2008 | 2007 | 2008 | 2007 | ||||||||
Reconciliation of net income to net cash provided | ||||||||||||
by operating activities: | ||||||||||||
Net income (loss) | $ | (126,040 | ) | $ | 32,874 | $ | 91,553 | $ | 189,712 | |||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||
provided by operating activities: | ||||||||||||
Loss related to hurricanes | - | - | 6,980 | - | ||||||||
(Gain) loss on insurance settlement | 696 | 1,097 | 2,296 | (5,243 | ) | |||||||
(Gain) loss on sale of proved properties | (9,494 | ) | 367 | (63,557 | ) | 367 | ||||||
Depletion, depreciation, amortization, | ||||||||||||
and asset retirement obligation liability accretion | 95,260 | 64,919 | 314,330 | 227,596 | ||||||||
Bad debt expense | 143 | - | 16,735 | - | ||||||||
Exploratory dry hole expense | 240 | 1,651 | 6,823 | 14,365 | ||||||||
Impairment of proved properties | 292,100 | - | 302,230 | - | ||||||||
Impairment of goodwill | 9,452 | - | 9,452 | - | ||||||||
Abandonment and impairment of unproved properties | 34,754 | 870 | 39,049 | 4,756 | ||||||||
Unrealized derivative (gain) loss | (12,011 | ) | 3,234 | (11,209 | ) | 5,458 | ||||||
Change in Net Profits Plan liability | (80,941 | ) | 43,875 | (34,040 | ) | 50,823 | ||||||
Stock-based compensation expense (1) | 4,335 | 1,489 | 14,812 | 10,095 | ||||||||
Deferred income taxes | (60,597 | ) | 13,666 | 40,634 | 92,955 | |||||||
Other | (97 | ) | (5,329 | ) | (3,593 | ) | (10,497 | ) | ||||
Changes in current assets and liabilities: | ||||||||||||
Accounts receivable | 25,128 | (6,349 | ) | (14,327 | ) | (6,557 | ) | |||||
Refundable income taxes | (8,578 | ) | 2,164 | (12,228 | ) | 6,751 | ||||||
Prepaid expenses and other | (3,533 | ) | (8,660 | ) | (1,504 | ) | 19,375 | |||||
Accounts payable and accrued expenses | (47,111 | ) | 13,217 | (12,348 | ) | 40,769 | ||||||
Excess income tax benefit from the exercise of stock options | (3,586 | ) | (2,275 | ) | (13,867 | ) | (9,933 | ) | ||||
Net cash provided by operating activities | 110,120 | 156,810 | 678,221 | 630,792 | ||||||||
Cash flows from investing activities: | ||||||||||||
Proceeds from insurance settlement | - | (1,116 | ) | - | 5,948 | |||||||
Proceeds from sale of oil and gas properties | 23,664 | 171 | 178,867 | 495 | ||||||||
Capital expenditures | (251,125 | ) | (137,637 | ) | (745,617 | ) | (637,748 | ) | ||||
Acquisition of oil and gas properties | 1,610 | (150,233 | ) | (81,823 | ) | (182,883 | ) | |||||
Deposits to restricted cash | (14,398 | ) | - | (14,398 | ) | - | ||||||
Other | 9 | 25,300 | (9,814 | ) | 10,316 | |||||||
Net cash used in investing activities | (240,240 | ) | (263,515 | ) | (672,785 | ) | (803,872 | ) | ||||
Cash flows from financing activities: | ||||||||||||
Proceeds from credit facility | 1,739,500 | 268,086 | 2,571,500 | 822,000 | ||||||||
Repayment of credit facility | (1,609,500 | ) | (138,086 | ) | (2,556,500 | ) | (871,000 | ) | ||||
Excess tax benefit from the exercise of stock options | 3,586 | 2,275 | 13,867 | 9,933 | ||||||||
Net proceeds from issuance of senior convertible debt | - | (7 | ) | - | 280,657 | |||||||
Proceeds from sale of common stock | 561 | 3,665 | 11,888 | 10,007 | ||||||||
Repurchase of common stock | - | - | (77,202 | ) | (25,904 | ) | ||||||
Dividends paid | (3,110 | ) | (3,144 | ) | (6,186 | ) | (6,284 | ) | ||||
Other | (182 | ) | 186 | (182 | ) | (4,283 | ) | |||||
Net cash provided by (used in) financing activities | 130,855 | 132,975 | (42,815 | ) | 215,126 | |||||||
Net change in cash and cash equivalents | 735 | 26,270 | (37,379 | ) | 42,046 | |||||||
Cash and cash equivalents at beginning of period | 5,396 | 17,240 | 43,510 | 1,464 | ||||||||
Cash and cash equivalents at end of period | $ | 6,131 | $ | 43,510 | $ | 6,131 | $ | 43,510 | ||||
(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the consolidated statements of operations. | ||||||||||||
For the three-month periods ended December 31, 2008, and 2007, respectively, approximately $2.0 million and $600,000 of stock-based compensation expense | ||||||||||||
was included in exploration expense. For the years ended December 31, 2008, and 2007, respectively, approximately $5.8 million and $3.2 million | ||||||||||||
of stock-based compensation expense was included in exploration expense. For the three-month periods ended December 31, 2008, and 2007, respectively, | ||||||||||||
approximately $2.3 million and $889,000 of stock-based compensation expense was included in general and administrative expense. For the years | ||||||||||||
ended December 31, 2008, and 2007, respectively, approximately $9.0 million and $6.9 million of stock-based compensation expense was included in | ||||||||||||
general and administrative expense. |
ST. MARY LAND & EXPLORATION COMPANY | ||||||||||||
FINANCIAL HIGHLIGHTS | ||||||||||||
December 31, 2008 | ||||||||||||
Adjusted Net Income | ||||||||||||
(In thousands, except per share data) | ||||||||||||
Reconciliation of Net Income (Loss) (GAAP) | For the Three Months | For the Years | ||||||||||
to Adjusted Net Income (Non-GAAP): | Ended December 31, | Ended December 31, | ||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||
Reported Net Income (Loss) (GAAP) | $ | (126,040 | ) | $ | 32,874 | $ | 91,553 | $ | 189,712 | |||
Adjustments: | ||||||||||||
Change in Net Profits Plan liability | (80,941 | ) | 43,875 | (34,040 | ) | 50,823 | ||||||
Unrealized derivative (gain) loss | (12,011 | ) | 3,234 | (11,209 | ) | 5,458 | ||||||
(Gain) loss on sale of proved properties | (9,494 | ) | 367 | (63,557 | ) | 367 | ||||||
(Gain) loss on insurance settlement (2) | 696 | 1,097 | 2,296 | (5,243 | ) | |||||||
Bad debt expense associated with SemGroup, L.P. | (5 | ) | - | 16,635 | - | |||||||
(Gain) loss related to hurricanes (3) | - | - | 6,980 | - | ||||||||
Tax adjustment at effective rate for period | 35,318 | (17,071 | ) | 32,771 | (18,926 | ) | ||||||
Adjusted Net Income (Loss), before impairments | (192,477 | ) | 64,375 | 41,429 | 222,190 | |||||||
Non-cash impairments: | ||||||||||||
Impairment of proved properties | 292,100 | - | 302,230 | - | ||||||||
Abandonment and impairment of unproved properties | 34,754 | 870 | 39,049 | 4,756 | ||||||||
Impairment of goodwill | 9,452 | - | 9,452 | - | ||||||||
Tax adjustment for impairments at effective rate for period | (116,728 | ) | (306 | ) | (138,656 | ) | (1,751 | ) | ||||
Adjusted Net Income, non recurring items | ||||||||||||
& non cash impairments (4) | 27,101 | 64,939 | 253,504 | 225,195 | ||||||||
Adjusted Net Income Per Share (Non-GAAP) | ||||||||||||
Basic | $ | 0.44 | $ | 1.03 | $ | 4.07 | $ | 3.64 | ||||
Diluted | $ | 0.43 | $ | 1.00 | $ | 4.02 | $ | 3.48 | ||||
Average Number of Shares Outstanding | ||||||||||||
Basic | 62,212 | 63,300 | 62,243 | 61,852 | ||||||||
Diluted | 62,630 | 64,635 | 63,133 | 64,850 | ||||||||
(2) The (gain) loss on insurance settlement is included within line item other revenue on the consolidated statements of operations. | ||||||||||||
(3) The loss related to hurricanes is included within line item other expense on the consolidated statements of operations. | ||||||||||||
(4) Adjusted net income is calculated as net income (loss) adjusted for significant non-cash and non-recurring items. Non-cash charges include changes in | ||||||||||||
the Net Profits Plan liability, unusual and non-recurring bad debt expense, unrealized derivative gains and losses, impairment of proved properties, abandonment | ||||||||||||
and impairment of unproved properties, and impairment of goodwill. Non-recurring items include (gain) loss from sales of proved properties, | ||||||||||||
(gain) loss on insurance settlements, and (gain) loss related to hurricanes. The non-GAAP measure of adjusted net income is presented because management | ||||||||||||
believes it provides useful additional information to investors for analysis of St. Mary’s fundamental business on a recurring basis. In addition, management | ||||||||||||
believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of | ||||||||||||
companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment | ||||||||||||
decisions. Adjusted net income should not be considered in isolation or as a substitute for net income, income from operations, cash provided by operating activities | ||||||||||||
or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income | ||||||||||||
and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies. |
Discretionary Cash Flow | ||||||||||||
(In thousands) | ||||||||||||
Reconciliation of Net Cash Provided by Operating Activities | For the Three Months | For the Years | ||||||||||
(GAAP) to Discretionary Cash Flow (Non-GAAP): | Ended December 31, | Ended December 31, | ||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||
Net cash provided by operating activities (GAAP) | $ | 110,120 | $ | 156,810 | $ | 678,221 | $ | 630,792 | ||||
Exploration | 17,743 | 16,030 | 60,121 | 58,686 | ||||||||
Less: Exploratory dry hole expense | (240 | ) | (1,651 | ) | (6,823 | ) | (14,365 | ) | ||||
Less: Stock-based compensation expense included in exploration | (1,992 | ) | (599 | ) | (5,799 | ) | (3,215 | ) | ||||
Other | 97 | 5,329 | 3,593 | 10,497 | ||||||||
Bad debt expense | (143 | ) | - | (16,735 | ) | - | ||||||
Changes in current assets and liabilities | 37,680 | 1,903 | 54,274 | (50,405 | ) | |||||||
Discretionary cash flow (Non-GAAP) (5) | $ | 163,265 | $ | 177,822 | $ | 766,852 | $ | 631,990 | ||||
(5) Discretionary cash flow is computed as net income adjusted for (gain) loss on sale of proved properties, (gain) loss on insurance settlement, loss related | ||||||||||||
to hurricanes, depreciation, depletion, amortization and asset retirement obligation liability accretion, exploration expense, impairment of | ||||||||||||
proved properties, abandonment and impairment of unproved properties, impairment of goodwill, unrealized derivative (gain) loss, change in Net Profits Plan | ||||||||||||
liability, stock-based compensation expense, and deferred income taxes. The non-GAAP measure of discretionary cash flow is presented since management | ||||||||||||
believes that it provides useful additional information to investors for analysis of St. Mary's ability to internally generate funds for exploration, development, and | ||||||||||||
acquisitions. In addition, discretionary cash flow is widely used by professional research analysts and others in the valuation, comparison, and investment | ||||||||||||
recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research | ||||||||||||
analysts in making investment decisions. Discretionary cash flow should not be considered in isolation or as a substitute for net income, income from operations, | ||||||||||||
net cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since discretionary cash flow | ||||||||||||
excludes some, but not all items that affect net income and net cash provided by operating activities and may vary among companies, the discretionary cash flow | ||||||||||||
amounts presented may not be comparable to similarly titled measures of other companies. See the Consolidated Statements of Cash Flows herein for more | ||||||||||||
detailed cash flow information. |
ST. MARY LAND & EXPLORATION COMPANY | ||||||||
FINANCIAL HIGHLIGHTS | ||||||||
December 31, 2008 | ||||||||
Information on Reserves and Costs Incurred | ||||||||
Costs incurred in oil and gas producing activities: | ||||||||
For the Year Ended | ||||||||
December 31, | ||||||||
2008 | ||||||||
Development costs (6) | $ | 586,579 | ||||||
Exploration costs | 92,199 | |||||||
Acquisitions: | ||||||||
Proved properties | 51,567 | |||||||
Unproved properties - acquisitions of | ||||||||
proved properties (7) | 43,274 | |||||||
Unproved properties - other | 83,078 | |||||||
Total, including asset retirement obligation (8) | $ | 856,697 | ||||||
(6) Includes capitalized interest of $3.7 million. | ||||||||
(7) Represents a portion of the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties. | ||||||||
(8) Includes amounts relating to estimated asset retirement obligations of $15.4 million. | ||||||||
Proved oil and gas reserve quantities: | ||||||||
For the Year Ended | ||||||||
December 31, 2008 | ||||||||
Oil or Condensate MMBbls | Gas BCF | BCFE | ||||||
Developed and undeveloped: | ||||||||
Beginning of year | 78.8 | 613.5 | 1,086.5 | |||||
Revisions of previous estimate (9) | (22.6 | ) | (108.3 | ) | (244.2 | ) | ||
Discoveries and extensions | 0.7 | 41.1 | 45.1 | |||||
Infill reserves in an existing proved field | 5.4 | 92.4 | 125.0 | |||||
Purchases of minerals in place | 0.4 | 27.0 | 29.1 | |||||
Sales of reserves | (4.7 | ) | (33.4 | ) | (61.4 | ) | ||
Production | (6.6 | ) | (74.9 | ) | (114.6 | ) | ||
End of year | 51.4 | 557.4 | 865.5 | |||||
Proved developed reserves | ||||||||
Beginning of year | 68.3 | 426.6 | 836.3 | |||||
End of year | 47.1 | 433.2 | 715.8 | |||||
(9) For the year ended December 31, 2008, of the (244.2) BCFE downward revision of previous estimate (199.7) BCFE relates to price and (44.5) BCFE relates to performance. | ||||||||
Finding Cost and Reserve Replacement Ratios: (10) | ||||||||
Finding Costs in $ per MCFE | Excluding Sales | Including Sales | ||||||
Drilling, excluding performance and price revisions | $ | 3.99 | $ | 6.25 | ||||
Drilling, including performance revisions | $ | 5.40 | $ | 10.57 | ||||
Drilling and acquisitions, excluding performance and price revisions | $ | 3.67 | $ | 5.30 | ||||
Drilling and acquisitions, including performance revisions | $ | 4.72 | $ | 7.83 | ||||
Acquisitions | $ | 1.77 | n/a | |||||
All-in, excluding price revisions | $ | 5.54 | $ | 9.18 | ||||
All-in, including performance and price revisions | $ | (19.04 | ) | $ | (8.05 | ) | ||
Reserve Replacement Ratios | ||||||||
Drilling, excluding performance and price revisions | 148% | 95% | ||||||
Drilling, including performance revisions | 110% | 56% | ||||||
Drilling and acquisitions, excluding performance and price revisions | 174% | 120% | ||||||
Drilling and acquisitions, including performance revisions | 135% | 81% | ||||||
Acquisitions | 25% | n/a | ||||||
All-in, excluding price revisions | 135% | 81% | ||||||
All-in, including performance and price revisions | -39% | -93% | ||||||
(10) Finding costs and reserve replacement ratios are common metrics used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. The metrics are easily calculated from information provided in the sections "Costs incurred in oil and gas producing activities" and "Proved oil and gas reserve quantities" above. Finding cost provides some information as to the cost of adding proved reserves from various activities. Reserve replacement provides information related to how successful a company is at growing its proved reserve base. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in "Costs incurred in oil and gas producing activities." The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. |
ST. MARY LAND & EXPLORATION COMPANY |
FINANCIAL HIGHLIGHTS |
December 31, 2008 |
Finding Costs Definitions: |
> Drilling, excluding performance and price revisions - numerator defined as the sum of development costs and exploration costs divided by a denominator defined as the sum of discoveries and extensions and infill reserves in an existing proved field. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> Drilling and acquisitions, excluding performance and price revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> Drilling and acquisitions, excluding performance and price revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> Drilling and acquisitions, including performance revisions - numerator defined as the sum of development costs, exploration costs, and acquisition costs for proved properties divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> Acquisitions - numerator defined as acquisition costs for proved properties divided by a denominator defined as purchases of minerals in place. |
> All-in, excluding price revisions - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> All-in, including performance and price revisions - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
Reserve Replacement Ratio Definitions: |
> Drilling, excluding performance and price revisions - numerator defined as the of sum of discoveries and extensions and infill reserves in an existing proved field divided by production. To consider the impact divestitures on this metric, further include sales of reserves in denominator. |
> Drilling , including performance revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and performance revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator. |
> Drilling and acquisitions, excluding performance and price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and purchases of minerals in place divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator. |
> Drilling and acquisitions, including performance revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator. |
> Acquisitions - numerator defined as purchases of minerals in place divided by production. |
> All-in, excluding price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and performance revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator. |
> All-in, including performance and price revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, performance revisions, and price revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator. |