SM Energy Reports Results for Fourth Quarter of 2010 and 2010 Proved Reserves and Costs Incurred; Provides Operational Update
-- Quarterly record average daily production of 344.4 MMCFE/d; exceeds
guidance of 305 - 330 MMCFE/d
-- Reported GAAP net income of $37.1 million, or $0.57 per diluted share;
adjusted net income of $29.7 million, or $0.46 per diluted share
-- Proved reserves at year-end 2010 up 27% from 2009 to 984.5 BCFE
-- Eagle Ford shale and Bakken / Three Forks programs remain focus of
capital program
DENVER--(BUSINESS WIRE)-- SM Energy Company (NYSE: SM) today reports financial results for the fourth quarter of 2010 and provides an update on the Company's operating and financial activities. In addition, a new presentation for the fourth quarter earnings and operational update has been posted on the Company's website at sm-energy.com. This presentation will be referenced in the conference call scheduled for 8:00 a.m. Mountain time (10:00 a.m. Eastern time) on February 25, 2011. Information for the earnings call can be found below.
MANAGEMENT COMMENTARY
Tony Best, CEO and President, remarked, "Last year was a transformational year for SM Energy. We entered 2010 with a plan to advance our resource plays in inventory and get them ready for full-scale development. Our focus became centered on oil and liquids rich plays such as the Eagle Ford shale and Bakken/Three Forks and we saw continued success in these programs. For the year, SM Energy replaced nearly 350% of its production organically, while keeping a strong balance sheet. We are well positioned as we enter 2011 and we remain focused on building shareholder value with the continued growth in our key resource plays."
FOURTH QUARTER 2010 RESULTS
SM Energy posted net income for the fourth quarter of 2010 of $37.1 million, or $0.57 per diluted share. This compares to $990 thousand, or $0.02 per diluted share, for the same period in 2009. Adjusted net income for the fourth quarter was $29.7 million, or $0.46 per diluted share, versus $20.1 million, or $0.31 per diluted share, for the fourth quarter of 2009. Adjusted net income excludes certain items that the Company believes affect the comparability of operating results. Items excluded are generally one-time items or are items whose timing and/or amount cannot be reasonably estimated. 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,
2010 2009
Weighted-average diluted share count 64.9 64.1
(in millions)
$ in Per $ in Per
millions Diluted millions Diluted
Share Share
Reported net income $37.1 $0.57 $1.0 $0.02
Adjustments net of tax:
Change in Net Profits Plan liability ($3.0 ) ($0.05 ) $4.3 $0.07
Unrealized derivative loss $8.2 $0.13 $2.0 $0.03
Gain on property sales ($14.7 ) ($0.23 ) ($13.8 ) ($0.21 )
Bad debt recovery associated with - - ($3.1 ) ($0.05 )
SemGroup, L.P.
Adjusted net income (loss), before $27.8 $0.43 ($9.5 ) ($0.15 )
impairments
Non-cash impairments net of tax:
Impairment of proved properties $3.9 $0.06 $13.5 $0.21
Abandonment and impairment of ($1.9 ) ($0.03 ) $15.7 $0.24
unproved properties
Impairment of materials inventory - - $0.5 $0.01
Adjusted net income $29.7 $0.46 $20.1 $0.31
NOTE: Totals may not sum due to
rounding
Operating cash flow was $176.4 million for the fourth quarter of 2010 compared to $144.2 million for the same period in 2009. Net cash provided by operating activities was $78.7 million for the fourth quarter of 2010 compared with $83.1 million for the same period in 2009.
Adjusted net income and operating 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.
SM Energy reported average daily production of 344.4 MMCFE/d for the fourth quarter, which was above the guidance range of 305 to 330 MMCFE/d. Production growth was driven by strong results in the Company's Eagle Ford shale and Haynesville shale programs. Sequentially, reported production grew 15% in the fourth quarter of 2010 over the preceding quarter.
Total operating revenues and other income for the fourth quarter of 2010 was $294.1 million compared to $242.0 million for the same period in 2009. In the fourth quarter, the Company's average equivalent price, net of hedging, was $7.98 per MCFE, which is an increase of 4% from the $7.69 per MCFE realized in the comparable period in 2009. Average realized prices, inclusive of hedging activities, for the fourth quarter were $6.00 per Mcf, which was essentially flat from the same quarter in 2009, and $70.30 per barrel, which was an increase of 9% from 2009. SM Energy reports its gas volumes on a "wet gas" basis, meaning that revenue dollars associated with natural gas liquids ("NGLs") are reported within the Company's natural gas revenues.
Lease operating expense ("LOE") in the fourth quarter was $1.06 per MCFE, which is below the Company's guidance of $1.15 to $1.20 per MCFE. This represents a 19% decrease from the $1.31 per MCFE in the comparable period last year. Sequentially, lease operating expense remained flat in the fourth quarter of 2010 from the third quarter.
Transportation expense in the fourth quarter was $0.22 per MCFE, which is within the guidance range of $0.20 to $0.22 per MCFE. The reported per unit expense increased 10% from the comparable period in 2009. Transportation expense also increased 22% from $0.18 per MCFE in the third quarter of 2010. The increase in transportation reflects the growth in production in areas where higher transportation costs exist.
Production taxes for the fourth quarter of 2010 were $0.52 per MCFE, which was essentially flat from the same period a year ago. Sequentially, production taxes increased 33% from the third quarter of 2010. This increase was the result of production tax credits realized in the third quarter of 2010 related to severance tax holidays. The Company's realized production tax rate for the fourth quarter was 6.5%, which was essentially within the provided guidance of 7% of pre-hedge oil and natural gas revenue.
Total general and administrative ("G&A") expense for the fourth quarter of 2010 was $1.00 per MCFE, which is above the guidance range of $0.88 to $0.96 per MCFE. Cash G&A expense was $0.73 per MCFE for the quarter, compared to a guidance range of $0.54 to $0.58 per MCFE. Non-cash G&A for the quarter was $0.16 per MCFE versus a guidance range of $0.18 to $0.20 per MCFE. G&A related to cash payments from the Company's legacy Net Profits Plan ("NPP") program was $0.11 per MCFE in the quarter compared to a guidance range of $0.16 to $0.18 per MCFE. The total G&A expense variance from guidance is largely the result of higher compensation costs related to annual performance-based bonus accruals for 2010. On a sequential basis, G&A expense increased 4% from the third quarter of 2010.
Depletion, depreciation and amortization expense ("DD&A") was $2.99 per MCFE in the fourth quarter of 2010, which was within the Company's guidance range of $2.90 to $3.20 per MCFE. DD&A increased 4%, or $0.11 per MCFE, between the fourth quarters of 2010 and 2009. Sequentially, DD&A in the fourth quarter of 2010 decreased 2% from $3.05 per MCFE in the third quarter. The Company's DD&A rate is impacted by a number of factors, including year-end proved reserves and divestitures.
PROVED RESERVES AND COSTS INCURRED
Below is a roll-forward of the Company's proved reserves from year-end 2009 to year-end 2010.
(BCFE)
Beginning of year 772.2
Revisions of previous estimate (engineering, price, and aged 24.7
PUD locations)
Discoveries and extensions 270.2
Infill reserves in an existing proved field 114.0
Purchases of minerals in place 0.2
Sales of reserves (86.8)
Production (110.0)
End of year 984.5
SM Energy's estimate of proved reserves as of December 31, 2010, was 984.5 BCFE, which is an increase of 27% from 772.2 BCFE at the end of 2009. These reserves are comprised of 57.4 MMBbl of oil and 640.0 Bcf of natural gas, and are 70% proved developed, compared to 82% proved developed at the end of 2009. The before income tax PV-10 value of the Company's estimated proved reserves at December 31, 2010 was $2.3 billion, which was roughly $1.0 billion higher than the prior year. Over 80% of SM Energy's estimated proved reserves by value were audited by an independent reserve engineering firm.
Prices used at year-end to calculate the Company's estimate of proved reserves were $4.38 per MMBTU of natural gas and $79.43 per barrel of oil, using the trailing 12-month arithmetic average of the first of month price. These prices are 13% and 30% higher than the prices used at the end of 2009 for natural gas and oil, respectively.
In 2010, SM Energy realized $2.14 per MCFE in drilling finding costs, excluding revisions, which is an improvement of 38% from $3.44 per MCFE realized in 2009. Drilling reserve replacement, excluding revisions, increased to 349% in 2010 from 100% in 2009.
Finding costs and reserve replacement ratios are non-GAAP financial measures - please refer to the respective definitions in the accompanying Financial Highlights section at the end of this release.
Below is a table detailing the Company's costs incurred in oil and gas producing activities for the year ended December 31, 2010.
Costs incurred in oil and gas producing activities:
For the Year Ended
December 31,
2010
(in thousands)
Development costs $299,308
Facility costs 80,328
Exploration costs 443,888
Acquisitions:
Proved properties 664
Unproved properties - other 53,192
Total, including asset retirement obligation $877,380
FINANCIAL POSITION AND LIQUIDITY
As of December 31, 2010, SM Energy had total long-term debt of $323.7 million. This was comprised of $275.7 million, net of debt discount, related to the Company's 3.50% Senior Convertible Notes and $48.0 million drawn on the long-term credit facility. The Company's debt-to-book capitalization ratio was 21% as of the end of the quarter.
On February 7, 2011, the Company closed the private offering of $350 million of 6.625% Senior Notes due 2019, which are unsecured and were issued at par value. The net proceeds will be used to repay outstanding balances under the credit facility, fund a portion of the Company's 2011 capital program and for general corporate purposes. As a result of the offering, the borrowing base for the long-term credit facility was automatically reduced from $1.1 billion to $1.0 billion; however, the Company's commitment amount under the credit facility of $678 million was not changed. SM Energy's debt-to-book capitalization ratio, pro forma for this offering, would be 34%.
OPERATIONAL UPDATE
Eagle Ford Shale
SM Energy is currently operating two (2) drilling rigs on its operated acreage in South Texas. The Company plans to increase its operated rig count to six (6) drilling rigs by the end of 2011. A third drilling rig is expected to arrive at the beginning of March 2011.
The Company continues to make improvements in its drilling times in the play. During 2010, drilling time per 1,000 ft. of penetration was reduced to 24 hours from 32 hours, a 25% improvement. A number of pilots to test downspacing potential and retained energy fracture stimulations are planned this year, both of which will provide important data regarding the ultimate spacing for the Company's development plans.
SM Energy has previously announced its intention to sell down a portion of its total 250,000 net acre Eagle Ford shale position. The data room for this planned transaction opened earlier this week and the Company expects to have an agreement completed in the second quarter of 2011.
Bakken / Three Forks
Two (2) drilling rigs are currently operating for SM Energy in the Williston Basin with a focus on horizontal development of the Bakken and Three Forks formations. A third operated rig is expected to arrive in April of 2011. The Company has increased its acreage position in the prospective portion of North Dakota to approximately 85,000 net acres, up from the previously reported 81,000 net acres.
Marcellus Shale Divestiture Update
To date, the Company has not received acceptable cash offers for its Marcellus shale position in north central Pennsylvania where it holds the rights to approximately 43,000 net acres. SM Energy continues to negotiate with interested parties.
Performance Guidance
The Company's guidance for the first quarter and the full year of 2011 is as follows:
1Q11 FY 2011
Production (BCFE) 30 - 33 128 - 132
LOE ($/MCFE) $1.10 - $1.15 $1.07 - $1.12
Transportation ($/MCFE) $0.30 - $0.35 $0.40 - $0.45
Production Taxes (% of pre-hedge O&G revenue) 7% 7%
G&A - cash NPP ($/MCFE) $0.16 - $0.18 $0.16 - $0.18
G&A - other cash ($/MCFE) $0.54 - $0.57 $0.55 - $0.58
G&A - non-cash ($/MCFE) $0.12 - $0.14 $0.13 - $0.15
G&A TOTAL ($/MCFE) $0.82 - $0.89 $0.84 - $0.91
DD&A ($/MCFE) $2.95 - $3.15 $2.95 - $3.15
Non-cash interest expense ($MM) $3.6 $15.0
Effective income tax rate range 37.4% - 37.9%
% of income tax that is current <10%
EARNINGS CALL INFORMATION
The Company has scheduled a teleconference to discuss the fourth quarter results on February 25, 2011 at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The call participation number is 800-260-8140 and the participant passcode is 21918282. An audio replay of the conference call will be available approximately two hours after the call at 888-286-8010, with the passcode 43039171. International participants can dial 617-614-3672 to take part in the call, using passcode 21918282 and can access a replay of the call at 617-801-6888, using passcode 43039171. Replays can be accessed through March 11, 2011.
The call will be webcast live and can be accessed at SM Energy Company's website at sm-energy.com. An audio recording of the call will be available at that site through March 11, 2011.
INFORMATION ABOUT FORWARD LOOKING STATEMENTS
This release contains forward looking statements within the meaning of the securities laws, including forecasts and projections. The words "will," "believe," "budget," "anticipate," "plan," "intend," "estimate," "forecast," "look," and "expect" and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, which may cause SM Energy'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, uncertainties inherent in projecting future rates of production from drilling activities and acquisitions, the ability of midstream service providers to purchase or market the Company's production, the availability of debt and equity financing for purchasers of oil and gas properties, 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 risks associated with the Company's hedging strategy, the uncertain nature of the expected benefits from divestitures or joint ventures of oil and gas properties, the ability to close announced divestitures or joint ventures of oil and gas properties, and other such matters discussed in the "Risk Factors" section of SM Energy's 2010 Annual Report on Form 10-K, which is expected to be filed on or around February 25, 2011. Although SM Energy may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by the securities laws.
INFORMATION ABOUT PROVED RESERVES
This press release contains references to certain items pertaining to the process used to estimate the Company's proved reserves and their PV-10 value, which is equal to the standardized measure of discounted future net cash flows from proved reserves on the applicable date, before deducting future income taxes, discounted at 10 percent. SM Energy believes that the presentation of pre-tax PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's proved reserves prior to taking into account future corporate income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 value as a basis for comparison of the relative size and value of the Company's proved reserves to other peer companies. SM Energy's pre-tax PV-10 value for estimated proved reserves as of December 31, 2010 may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2010 by reducing the Company's pre-tax PV-10 value by the discounted future income taxes associated with such reserves, and a reconciliation is provided below.
Reconciliation of standardized measure (GAAP) to PV-10 value (Non-GAAP):
As of December 31,
2010
(in thousands)
Standardized measure of discounted future $ 1,666,367
net cash flows (GAAP)
Add: 10 percent annual discount, net of 1,294,632
income taxes
Add: future income taxes 1,335,576
Undiscounted future net cash flows $ 4,296,575
Less: 10 percent annual discount without tax (1,952,244)
effect
PV-10 value (Non-GAAP) $ 2,344,331
Additionally, the Company believes its use of an independent reserve auditor is a fact of interest to investors and analysts who follow the Company. More information on these items will be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2010 to be filed with the Securities and Exchange Commission on February 25, 2011.
ABOUT THE COMPANY
SM Energy Company, formerly named St. Mary Land & Exploration Company, is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas, natural gas liquids and crude oil. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at sm-energy.com.
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2010
Guidance For the Three Months
Comparison
Ended December 31, 2010
Actual Guidance
Range
Oil and gas
production 344.4 305 -
(MMCFE per 330
day)
Lease 1.15
operating $1.06 $ -
expense (per $1.20
MCFE)
Transportation 0.20
expense (per $0.22 $ -
MCFE) $0.22
Production
taxes, as a
percentage of 7 % 7 %
pre-hedge
revenue
General and 0.54
administrative $0.73 $ -
- cash (per $0.58
MCFE)
General and
administrative 0.16
- cash related $0.11 $ -
to Net Profits $0.18
Plan (per
MCFE)
General and 0.18
administrative $0.16 $ -
- non-cash $0.20
(per MCFE)
General and 0.88
administrative $1.00 $ -
- TOTAL (per $0.96
MCFE)
Depreciation, 2.90
depletion, and $2.99 $ -
amortization $3.20
(per MCFE)
Production For the Three Months For the Years
Data
Ended December 31, Ended December 31,
2010 2009 Percent 2010 2009 Percent
Change Change
Average
realized sales
price, before
hedging:
Oil (per Bbl) $ 77.46 $ 68.98 12 % $ 72.65 $ 54.40 34 %
Gas (per Mcf) 5.23 4.88 7 % 5.21 3.82 36 %
Average
realized sales
price, net of
hedging:
Oil (per Bbl) $ 70.30 $ 64.43 9 % $ 66.85 $ 56.74 18 %
Gas (per Mcf) 6.00 6.07 -1 % 6.05 5.59 8 %
Production:
Oil (MMBbls) 1.8 1.5 21 % 6.4 6.3 0 %
Gas (Bcf) 20.7 17.1 21 % 71.9 71.1 1 %
BCFE (6:1) 31.7 26.1 21 % 110.0 109.1 1 %
Daily
production:
Oil (MBbls per 19.9 16.4 21 % 17.4 17.3 0 %
day)
Gas (MMcf per 224.9 185.3 21 % 196.9 194.8 1 %
day)
MMCFE per day 344.4 284.0 21 % 301.4 298.8 1 %
(6:1)
Margin
analysis per
MCFE:
Average
realized sales $ 7.90 $ 7.18 10 % $ 7.60 $ 5.65 35 %
price, before
hedging
Average
realized sales 7.98 7.69 4 % 7.82 6.94 13 %
price, net of
hedging
Lease
operating 1.06 1.31 -19 % 1.10 1.33 -17 %
expense
Transportation 0.22 0.20 10 % 0.19 0.19 0 %
Production 0.52 0.51 2 % 0.48 0.37 30 %
taxes
General and 1.00 0.80 25 % 0.97 0.70 39 %
administrative
Operating $ 5.18 $ 4.87 6 % $ 5.08 $ 4.35 17 %
margin
Depletion,
depreciation,
amortization,
and
asset
retirement
obligation $ 2.99 $ 2.88 4 % $ 3.06 $ 2.79 10 %
liability
accretion
Consolidated Statements of Operations
(In thousands, except per share amounts)
For the Three Months For the Years
Ended December 31, Ended December 31,
2010 2009 2010 2009
Operating revenues and other
income:
Oil and gas
production $ 250,160 $ 187,606 $ 836,288 $ 615,953
revenue
Realized oil and 2,694 13,418 23,465 140,648
gas hedge gain
Gain on
divestiture 23,094 22,076 155,277 11,444
activity
Marketed gas 16,083 16,977 70,110 58,459
system revenue
Other revenue 2,087 1,919 7,694 5,697
Total operating
revenues and 294,118 241,996 1,092,834 832,201
other income
Operating
expenses:
Oil and gas
production 56,961 52,872 195,075 206,800
expense
Depletion,
depreciation,
amortization,
and asset
retirement
obligation 94,806 75,140 336,141 304,201
liability
accretion
Exploration 21,027 13,414 63,860 62,235
Impairment of
proved 6,127 21,630 6,127 174,813
properties
Abandonment and
impairment of (3,012 ) 25,153 1,986 45,447
unproved
properties
Impairment of
materials - 774 - 14,223
inventory
General and 31,560 20,687 106,663 76,036
administrative
Recovery of bad - (5,189 ) - (5,189 )
debt expense
Change in Net
Profits Plan (4,656 ) 6,963 (34,441 ) (7,075 )
liability
Marketed gas 14,176 16,235 66,726 57,587
system expense
Unrealized 12,994 3,218 8,899 20,469
derivative loss
Other expense 956 1,065 3,027 13,489
Total operating 230,939 231,962 754,063 963,036
expenses
Income (loss) 63,179 10,034 338,771 (130,835 )
from operations
Nonoperating
income
(expense):
Interest income 53 10 321 227
Interest expense (4,727 ) (7,532 ) (24,196 ) (28,856 )
Income (loss)
before income 58,505 2,512 314,896 (159,464 )
taxes
Income tax
benefit (21,366 ) (1,522 ) (118,059 ) 60,094
(expense)
Net income $ 37,139 $ 990 $ 196,837 $ (99,370 )
(loss)
Basic
weighted-average 63,131 62,565 62,969 62,457
common shares
outstanding
Diluted
weighted-average 64,919 64,113 64,689 62,457
common shares
outstanding
Basic net income
(loss) per $ 0.59 $ 0.02 $ 3.13 $ (1.59 )
common share
Diluted net
income (loss) $ 0.57 $ 0.02 $ 3.04 $ (1.59 )
per common share
Consolidated Balance Sheets
(In thousands, except share amounts)
December 31, December 31,
ASSETS 2010 2009
Current assets:
Cash and cash equivalents $ 5,077 $ 10,649
Accounts receivable 163,190 116,136
Refundable income taxes 8,482 32,773
Prepaid expenses and other 45,522 14,259
Derivative asset 43,491 30,295
Deferred income taxes 8,883 4,934
Total current assets 274,645 209,046
Property and equipment
(successful efforts method), at
cost:
Land 1,491 1,371
Proved oil and gas properties 3,389,158 2,797,341
Less - accumulated depletion, (1,326,932 ) (1,053,518 )
depreciation, and amortization
Unproved oil and gas properties 94,290 132,370
Wells in progress 145,327 65,771
Materials inventory, at lower of 22,542 24,467
cost or market
Oil and gas properties held for 86,811 145,392
sale
Other property and equipment,
net of accumulated depreciation
of $15,480 in 2010 and $14,550 21,365 14,404
in 2009
2,434,052 2,127,598
Other noncurrent assets:
Derivative asset 18,841 8,251
Other noncurrent assets 16,783 16,041
Total other noncurrent assets 35,624 24,292
Total Assets $ 2,744,321 $ 2,360,936
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities:
Accounts payable and accrued $ 417,654 $ 236,242
expenses
Derivative liability 82,044 53,929
Deposit associated with oil and 2,355 6,500
gas properties held for sale
Total current liabilities 502,053 296,671
Noncurrent liabilities:
Long-term credit facility 48,000 188,000
Senior convertible notes, net of
unamortized
discount of $11,827 in 2010, and 275,673 266,902
$20,598 in 2009
Asset retirement obligation 69,052 60,289
Asset retirement obligation
associated with oil and gas 2,119 18,126
properties held for sale
Net Profits Plan liability 135,850 170,291
Deferred income taxes 443,135 308,189
Derivative liability 32,557 65,499
Other noncurrent liabilities 17,356 13,399
Total noncurrent liabilities 1,023,742 1,090,695
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value:
authorized - 200,000,000 shares;
issued: 63,412,800 shares in
2010 and 62,899,122 shares in
2009;
outstanding, net of treasury
shares: 63,310,165 shares in
2010
and 62,772,229 shares in 2009 634 629
Additional paid-in capital 191,674 160,516
Treasury stock, at cost: 102,635
shares in 2010 and 126,893 (423 ) (1,204 )
shares in 2009
Retained earnings 1,042,123 851,583
Accumulated other comprehensive (15,482 ) (37,954 )
loss
Total stockholders' equity 1,218,526 973,570
Total Liabilities and $ 2,744,321 $ 2,360,936
Stockholders' Equity
Consolidated Statements of Cash Flows
(In thousands)
For the Three Months For the Years
Ended December 31, Ended December 31,
2010 2009 2010 2009
Cash flows
from
operating
activities:
Net income $ 37,139 $ 990 $ 196,837 $ (99,370 )
(loss)
Adjustments
to reconcile
net income
(loss) to net
cash
provided by
operating
activities:
Gain on
divestiture (23,094 ) (22,076 ) (155,277 ) (11,444 )
activity
Depletion,
depreciation,
amortization,
and asset
retirement
obligation 94,806 75,140 336,141 304,201
liability
accretion
Exploratory
dry hole - 2,961 289 7,810
expense
Impairment of
proved 6,127 21,630 6,127 174,813
properties
Abandonment
and
impairment of (3,012 ) 25,153 1,986 45,447
unproved
properties
Impairment of
materials - 774 - 14,223
inventory
Stock-based
compensation 6,890 5,787 26,743 18,765
expense*
Recovery of
bad debt - (5,189 ) - (5,189 )
expense
Change in Net
Profits Plan (4,656 ) 6,963 (34,441 ) (7,075 )
liability
Unrealized
derivative 12,994 3,218 8,899 20,469
loss
Loss related - 28 - 8,301
to hurricanes
Amortization
of debt
discount and 3,442 3,291 13,464 12,213
deferred
financing
costs
Deferred 28,822 29,347 114,517 (39,735 )
income taxes
Plugging and (1,208 ) (14,286 ) (8,314 ) (26,396 )
abandonment
Other (908 ) 1,950 (3,993 ) 3,382
Changes in
current
assets and
liabilities:
Accounts (42,216 ) (12,101 ) (47,153 ) 46,743
receivable
Refundable (7,111 ) (29,952 ) 24,291 (19,612 )
income taxes
Prepaid
expenses and (35,875 ) 2,034 (35,363 ) (6,626 )
other
Accounts
payable and 6,075 (12,608 ) 53,198 (4,814 )
accrued
expenses
Excess income
tax benefit
(expense) 522 - (854 ) -
from the
exercise of
stock awards
Net cash
provided by 78,737 83,054 497,097 436,106
operating
activities
Cash flows
from
investing
activities:
Net proceeds
from sale of 52,003 38,761 311,504 39,898
oil and gas
properties
Proceeds from
insurance - 1,453 - 16,789
settlement
Capital (179,604 ) (86,787 ) (668,288 ) (379,253 )
expenditures
Acquisition
of oil and 21 (18 ) (664 ) (76 )
gas
properties
Receipts from
restricted - - - 14,398
cash
Other 2,367 3,150 (4,125 ) 4,152
Net cash used
in investing (125,213 ) (43,441 ) (361,573 ) (304,092 )
activities
Cash flows
from
financing
activities:
Proceeds from
credit 256,500 174,000 571,559 2,072,500
facility
Repayment of
credit (210,500 ) (221,000 ) (711,559 ) (2,184,500 )
facility
Debt issuance
costs related - - - (11,074 )
to credit
facility
Proceeds from
sale of 3,324 1,931 6,440 3,110
common stock
Dividends (3,153 ) (3,127 ) (6,297 ) (6,247 )
paid
Excess income
tax benefit
(expense) (522 ) - 854 -
from the
exercise of
stock awards
Other (1,185 ) (1,285 ) (2,093 ) (1,285 )
Net cash
provided by
(used in) 44,464 (49,481 ) (141,096 ) (127,496 )
financing
activities
Net change in
cash and cash (2,012 ) (9,868 ) (5,572 ) 4,518
equivalents
Cash and cash
equivalents 7,089 20,517 10,649 6,131
at beginning
of period
Cash and cash
equivalents $ 5,077 $ 10,649 $ 5,077 $ 10,649
at end of
period
* Stock-based compensation expense is a component of exploration expense and general and
administrative expense on the consolidated statements of operations. For the three months
ended December 31, 2010, and 2009, approximately $2.0 million and $1.9 million, respectively
of stock-based compensation expense was included in exploration expense. For the three months
ended December 31, 2010, and 2009, approximately $4.9 million and $3.9 million, respectively
of stock-based compensation expense was included in general and administrative expense. For
the Years ended December 31, 2010, and 2009, approximately $7.7 million and $6.3 million,
respectively of stock-based compensation expense was included in exploration expense. For the
Years ended December 31, 2010 and 2009, approximately $19.0 million and $12.5 million,
respectively of stock-based compensation expense was included in general and administrative
expense.
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,
2010 2009 2010 2009
Reported net
income (loss) $ 37,139 $ 990 $ 196,837 $ (99,370 )
(GAAP)
Adjustments
net of tax:
(1)
Change in Net
Profits Plan (2,956 ) 4,338 (21,529 ) (4,409 )
liability
Unrealized
derivative 8,249 2,005 5,563 12,755
loss
Gain on
divestiture (14,660 ) (13,753 ) (97,061 ) (7,131 )
activity
Bad debt
recovery
associated - (3,143 ) - (3,143 )
with Sem
Group, L.P.
Loss related
to hurricanes - 17 - 5,173
(2)
Adjusted net
income (loss),
before 27,772 (9,546 ) 83,810 (96,125 )
impairment
adjustments
Non-cash
impairments
net of tax:
(1)
Impairment of
proved 3,889 13,475 3,830 108,935
properties
Abandonment
and impairment (1,912 ) 15,670 1,241 28,320
of unproved
properties
Impairment of
materials - 482 - 8,863
inventory
Adjusted net
income,
non-recurring
items
& non-cash
impairments $ 29,749 $ 20,081 $ 88,881 $ 49,993
(Non-GAAP) (3)
Adjusted net
income per
share
(Non-GAAP)
Basic $ 0.47 $ 0.32 $ 1.41 $ 0.80
Diluted $ 0.46 $ 0.31 $ 1.37 $ 0.80
Average number
of shares
outstanding
Basic 63,131 62,565 62,969 62,457
Diluted 64,919 64,113 64,689 62,457
(1) Adjustments are shown net of tax using the effective income tax rate;
calculated by dividing the income tax benefit (expense) by income (loss) before
income taxes as stated on the consolidated statement of operations.
(2) The loss related to hurricanes is included within line item other expense on
the consolidated statements of operations.
(3) Adjusted net income excludes certain items that the Company believes affect
the comparability of operating results. Items excluded generally are one-time
items or are items whose timing and/or amount cannot be reasonably estimated.
These items include non-cash adjustments and impairments such as the change in the
Net Profits Plan liability, unrealized derivative loss, impairment of proved
properties, abandonment and impairment of unproved properties, impairment of
materials inventory, gain on divestiture activity, bad debt recovery associated
with Sem Group, L.P., and 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 SM Energy'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.
Operating Cash Flow
(In thousands)
Reconciliation
of net cash
provided by
operating
activities For the Three Months For the Years
(GAAP) to
Operating cash
flow
(Non-GAAP):
Ended December 31, Ended December 31,
2010 2009 2010 2009
Net cash
provided by
operating $ 78,737 $ 83,054 $ 497,097 $ 436,106
activities
(GAAP)
Changes in
current assets $ 78,605 $ 52,627 $ 5,881 $ (15,691 )
and
liabilities
Exploration $ 21,027 $ 13,414 63,860 62,235
Less:
Exploratory $ - $ (2,961 ) (289 ) (7,810 )
dry hole
expense
Less:
Stock-based
compensation $ (1,952 ) $ (1,917 ) (7,676 ) (6,314 )
expense
included in
exploration
Operating cash
flow $ 176,417 $ 144,217 $ 558,873 $ 468,526
(Non-GAAP) (4)
(4) Beginning in the third quarter of 2009 the Company changed its definition of
operating cash flow. Prior periods have been conformed to the current definition
and the change in the definition did not result in a material variance to results
under the prior definition. Operating cash flow is computed as net cash provided
by operating activities adjusted for changes in current assets and liabilities and
exploration, less exploratory dry hole expense, and stock-based compensation
expense included in exploration. The non-GAAP measure of operating cash flow is
presented because management believes that it provides useful additional
information to investors for analysis of SM Energy's ability to internally
generate funds for exploration, development, acquisitions, and to service debt. In
addition, operating 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.
Operating 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 operating 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
operating 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.
Information on Proved Reserves and Costs Incurred
Costs
incurred in
oil and gas
producing
activities:
For the
Year Ended
December
31,
2010
Development $ 299,308
costs
Facility 80,328
costs (5)
Exploration 443,888
costs
Acquisitions:
Proved 664
properties
Unproved
properties - 53,192
other
Total,
including
asset $ 877,380
retirement
obligation
(6) (7)
(5) Beginning December 31, 2010 facility costs are being disclosed separately, whereas
these costs were previously captured in Development costs.
(6) Includes capitalized interest of $4.3 million for the year ended December 31, 2010.
(7) Includes amounts relating to estimated asset retirement obligations of $5.8 million
for the year ended December 31, 2010.
Proved oil and gas reserve quantities:
For the Year Ended
December 31, 2010
Oil or Gas Equivalents Proved Proved
Condensate Developed Undeveloped
(MMBbl) (Bcf) (BCFE) (BCFE) (BCFE)
Total proved
reserves
Beginning of 53.8 449.5 772.2 630.3 141.9
year
Revisions of
previous 3.1 6.1 24.7 45.9 (21.2 )
estimate
Discoveries
and 16.2 172.9 270.2 140.0 130.2
extensions
Infill
reserves in 2.8 97.2 114.0 41.1 72.9
an existing
proved field
Purchases of
minerals in - 0.2 0.2 0.2 -
place
Sales of (12.1 ) (14.0 ) (86.8 ) (76.9 ) (9.9 )
reserves
Production (6.4 ) (71.9 ) (110.0 ) (110.0 ) -
Conversions 16.7 (16.7 )
End of year 57.4 640.0 984.5 687.3 297.2
PV-10 value $ 2,344.3 $ 2,053.6 $ 290.8
(in millions)
Proved
developed
reserves
Beginning of 48.1 342.0 630.3
year
End of year 46.0 411.0 687.3
Finding Cost
and Reserve
Replacement
Ratios: (8)
Finding Costs
in $ per MCFE
Drilling,
excluding $ 2.14
revisions
Drilling,
including $ 2.01
revisions
All-in $ 2.14
Reserve
Replacement
Ratios
Drilling,
excluding 349 %
revisions
Drilling,
including 372 %
revisions
All-in 372 %
(8) 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.
Finding Costs Definitions:
> Drilling, excluding revisions - numerator defined as the sum of development costs and
exploration costs and facility 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 of divestitures on this metric, further include sales of reserves in
denominator.
> Drilling, including revisions - numerator defined as the sum of development costs and
exploration costs and facility costs divided by a denominator defined as the sum of
discoveries and extensions, infill reserves in an existing proved field, and revisions.
To consider the impact of divestitures on this metric, further include sales of reserves
in denominator.
> All-in - 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
revisions. To consider the impact of divestitures on this metric, further include sales
of reserves in denominator.
Reserve Replacement Ratio Definitions:
> Drilling, excluding revisions - numerator defined as the sum of discoveries and
extensions and infill reserves in an existing proved field divided by production. To
consider the impact of divestitures on this metric, further include sales of reserves in
denominator.
> Drilling, including revisions - numerator defined as the sum of discoveries and
extensions, infill reserves in an existing proved field, and revisions divided by
production. To consider the impact of divestitures on this metric, further include sales
of reserves in denominator.
> All-in - numerator defined as the sum of discoveries and extensions, infill reserves in
an existing proved field, purchases of minerals in place, and revisions divided by
production. To consider the impact of divestitures on this metric, further include sales
of reserves in denominator.
Source: SM Energy
Released February 24, 2011