EXHIBIT 99.1

For Information
Brent A. Collins
303-861-8140

FOR IMMEDIATE RELEASE


ST. MARY REPORTS RESULTS FOR FOURTH QUARTER OF 2009
AND 2009 PROVED RESERVES AND CAPITAL EXPENDITURES;
PROVIDES OPERATIONAL AND 2010 GUIDANCE UPDATE

·  
Quarterly production of 26.1 BCFE at high end of guidance of 24.75 – 26.25 BCFE

·  
Reported GAAP net income of $990 thousand, or $0.02 per diluted share; adjusted net income of $20.1 million or $0.31 per diluted share

·  
Proved reserves at year-end 2009 of 772.2 BCFE

·  
Positive results from additional wells in Eagle Ford shale program, where leased and optioned acreage has increased 10% to 250,000 net acres


DENVER, February 22, 2010 –
St. Mary Land & Exploration Company (NYSE: SM) today reports financial results from the fourth quarter of 2009.  In addition, a new presentation for the fourth quarter earnings and operational update has been posted at the Company’s website at stmaryland.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 23, 2010.  Information for the earnings call can be found below.


MANAGEMENT COMMENTARY

Tony Best, CEO and President, remarked, “Last year was a transformational year for St. Mary.  We entered 2009 with a great deal of uncertainty regarding the economy and we responded appropriately by cutting back our level of capital investment, particularly in development activities.  Our focus shifted to advancing a number of exploration projects and we were rewarded as the Eagle Ford shale emerged as an exciting new resource play in our portfolio.   For the year, St. Mary replaced production and held production on retained properties flat while investing 62% less on development activities compared to 2008.  We are well positioned as we enter 2010, with an inventory of projects stronger than at any time in our recent history and ample liquidity to fund our programs.”


 
FOURTH QUARTER 2009 RESULTS

St. Mary posted net income for the fourth quarter of 2009 of $990 thousand, or $0.02 per diluted share.  This compares to a net loss of ($127.1) million, or a loss of ($2.04) per diluted share, for the same period in 2008.  Adjusted net income for the quarter, which adjusts for significant non-recurring or unusual non-cash items, was $20.1 million, or $0.31 per diluted share, versus $26.0 million, or $0.42 per diluted share, for the fourth quarter of 2008.  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,
 
   2009     2008   
Weighted-average diluted share count (in millions)
      64.1           62.2  
 
$ in millions
 
Per Diluted Share
 
$ in millions
 
Per Diluted Share
 
Reported net income (loss)
$ 1.0   $ 0.02   $ (127.1 ) $ (2.04 )
After –tax adjustments**
                       
Change in Net Profits Plan liability
$ 4.3   $ 0.07   $ (52.8 ) $ (0.85 )
Unrealized derivative (gain) loss
$ 2.0   $ 0.03   $ (7.8 ) $ (0.13 )
Gain on property sales
$ (13.8 ) $ (0.21 ) $ (6.2 ) $ (0.10 )
Bad debt recovery associated with SemGroup, L.P.
$ (3.1 ) $ (0.05 )   -     -  
Loss on insurance settlement
  -     -   $ 0.5   $ 0.01  
                         
Adjusted net loss, before impairments
$ (9.5 ) $ (0.15 ) $ (193.5 ) $ (3.11 )
                         
After –tax non-cash impairments**
                       
Impairment of proved properties
$ 13.5   $ 0.21   $ 190.7   $ 3.07  
Abandonment & impairment of unproved properties
$ 15.7   $ 0.24   $ 22.7   $ 0.36  
Impairment of goodwill
  -     -   $ 6.2   $ 0.10  
Impairment of materials inventory
$ 0.5   $ 0.01     -     -  
                         
Adjusted net income
$ 20.1   $ 0.31   $ 26.0   $ 0.42  
                         
NOTE:  Totals may not add due to rounding
                       
* On January 1, 2009, the Company adopted new authoritative guidance under FASB ASC Topic 470-20, "Debt with Conversion and Other Options" ("ASC Topic 470") which required retrospective application. As result, prior period balances presented have been adjusted to reflect the period-specific effects of applying ASC Topic 470.
** The Company’s standard practice is to use the effective income tax rate for the respective period when adjusting pre-tax items in the calculation of adjusted net income. For the fourth quarter of 2009, the full year effective tax rate of 38% was used in lieu of the quarterly effective tax rate. This is due to minor changes in permanent tax deductions disproportionately impacting the effective tax rate in a period when the Company had little pre-tax book income.
 

Discretionary cash flow was $144.2 million for the fourth quarter of 2009 compared to $163.6 million for the same period in 2008.  Net cash provided by operating activities was $83.1 million for the fourth quarter of 2009 compared with $110.4 million for the same period in 2008.
 
2

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 quarterly production of 26.1 BCFE for the fourth quarter of 2009, which was at the upper end of the guidance range of 24.75 to 26.25 BCFE.  Reported production for the same period last year was 30.0 BCFE.  Production from retained properties, which adjusts for divestitures that have taken place over the past two years, was 25.2 and 27.8 BCFE for the fourth quarters of 2009 and 2008, respectively.  Sequentially, reported production and production from retained properties in the fourth quarter of 2009 were essentially flat with the preceding quarter.

Total operating revenues and other income for the fourth quarter of 2009 was $242.0 million compared to $258.2 million for the same period in 2008.  In the fourth quarter of 2009, the Company’s average equivalent price per MCFE, net of hedging, was $7.69 per MCFE, which is a decrease of 2% from the $7.84 per MCFE realized in the comparable period in 2008.

Lease operating expense in the fourth quarter of 2009 of was $1.31 per MCFE, which is below the Company’s guidance of $1.35 to $1.40 per MCFE.  This represents an 18% decrease from the $1.59 per MCFE in the comparable period last year.  Sequentially, lease operating expense remained flat in the fourth quarter of 2009 from the third quarter.

Transportation expense in the fourth quarter of 2009 was $0.20 per MCFE, which is within the guidance range of $0.20 to $0.25 per MCFE.  The reported per unit expense remained flat from the comparative period in 2008.  Transportation expense per MCFE was also unchanged from the third quarter of 2009.

Production taxes for the fourth quarter of 2009 were $0.51 per MCFE, which is higher than the guidance of $0.45 to $0.50 per MCFE that had previously been provided and was 31% higher on a per unit basis than the same period a year ago.  Sequentially, production taxes increased $0.34 per MCFE in the third quarter of 2009.  Production taxes are a function of the pre-hedged oil and natural gas revenue realized in the respective periods.

Total general and administrative (“G&A”) expense for the fourth quarter of 2009 was $0.80 per MCFE, which is below the guidance range of $0.86 to $0.93 per MCFE.  The variance from guidance is largely the result of lower compensation related costs than had been previously assumed.  On a sequential basis, general and administrative remained essentially flat.

Depletion and depreciation expense decreased 9%, or $0.30 per MCFE, between the fourth quarters of 2009 and 2008.  Year over year, DD&A per MCFE decreased to $2.88 per MCFE from $3.18 per MCFE.  The decrease in DD&A is largely due to the reduction
 
3
 
of the book value of the Company’s oil and gas assets as a result of impairments that have been recognized over the past year.  Sequentially, DD&A in the fourth quarter of 2009 increased 13% from $2.54 per MCFE in the third quarter.  Guidance for DD&A in the fourth quarter was $2.50 to $2.70 per MCFE.  The sequential increase and the variance from guidance is the result of a decrease in the Company’s year-end proved reserves, which resulted in a smaller base over which capitalized costs related to the Company’s producing properties are depleted and resulted in a higher DD&A rate for the period.

Impairment of proved properties was $21.6 million in the fourth quarter of 2009 compared to $292.1 million for the comparable period in 2008.  The majority of the impairment in the fourth quarter of 2009 related to properties located in the Company’s ArkLaTex region.  Decline in year-end 2008 proved reserves and lower natural gas prices at the end of 2008 were major contributors to the 2008 impairment of proved properties.

Abandonments and impairments of unproved properties were $25.2 million and $34.8 million for the fourth quarters of 2009 and 2008, respectively.  The 2009 amount includes roughly $12 million related to leasehold in the Mid-Continent region that is either expiring or is being impaired since the Company will not develop it under its current capital investment allocation.  The remainder relates to leasehold that will not be developed given the Company’s current view regarding capital allocation or is believed to not be prospective.

In the fourth quarter of 2008, the Company fully impaired the goodwill associated with an acquisition made in 2005.

Exploration expense of $13.4 million was recognized in the fourth quarter of 2009, compared to $17.7 million in the same period in 2008.  The decrease reflects a decrease in exploration overhead in 2009.  Geologic and geophysical spending was relatively consistent between the two periods.

In the fourth quarter of 2009, St. Mary recognized a pre-tax non-cash charge of $7.0 million as a result of the increase in the Net Profits Plan (“NPP”) liability, compared to a benefit of $80.9 million in the fourth quarter of 2008.  This periodic expense is a reflection of the change in the liability during the respective periods.  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.

St. Mary’s effective tax rate for 2009 was 38%.  During the fourth quarter, due primarily to deductions driven by increased drilling activity, the Company determined a net operating loss could be carried back to 2005 resulting in a significant tax refund.  This resulted in certain “permanent” tax deductions which carry limitations to be reversed in the fourth quarter provision.  These items totaled only $614,000 but due to the relatively small book pre-tax income amount in the fourth quarter, the adjustment caused the
 
4
 
effective rate for the quarter to increase to roughly 60%.  This had minimal impact on the full year rate of 38%.


FULL YEAR PRODUCTION

Following is a table detailing the Company’s full year production for 2009 compared to 2008 which adjusts for divestiture efforts over the last two years.


Full Year Production (in BCFE)
 
 
2008
 
2009
 
Difference
 
%Difference
 
Total properties
114.6   109.1   (-5.5 ) -5%  
Production contribution of sold properties
(10.1 ) (5.1 ) (5.0 )    
Retained production
104.5   103.9   (0.6 ) -1%  

Despite the decrease in capital expenditures in 2009 compared to 2008 and the focus on exploration activities last year, St. Mary managed to keep production from the retained properties flat year over year.


PROVED RESERVES AND COST INCURRED

Below is a roll-forward of the Company’s proved reserves from year-end 2008 to year-end 2009.


 
(BCFE)
 
Beginning of year
865.5  
     
Revisions of previous estimate (engineering and price)
(49.6 )
Discoveries and extensions
72.3  
Infill reserves in an existing proved field
37.3  
Purchases of minerals in place
-  
Sales of reserves
(44.2 )
Production
(109.1 )
     
End of year
772.2  


St. Mary’s proved reserves as of December 31, 2009, were 772.2 BCFE, which is a decrease of 11% from 865.5 BCFE at the end of 2008.  The reserves are comprised of 53.8 MMBbl of oil and 449.5 Bcf of natural gas, and are 82% proved developed.  The before income tax PV-10 value of St. Mary’s proved reserves at December 31, 2009, was $1.3 billion ( 98% of which relates to the proved developed reserves), which is essentially flat with last year’s PV-10 value.  Over 85% of St. Mary’s proved reserves by value were reviewed by an outside reserve engineering firm.  More detailed information
 
5
 
regarding the breakdown of these proved reserves by product and development status is available in the accompanying Financial Highlights.  The Company’s management will discuss its proved reserves on the conference call scheduled for Tuesday, February 23, 2010.

Prices used at year end to calculate the Company’s estimate of proved reserves were $3.87 per MMBTU of natural gas and $61.18 per barrel of oil and reflect the SEC’s new pricing methodology which requires the use of the trailing 12-month arithmetic average of the first of month price.  These prices are 32% lower and 37% higher than the prices used at the end of 2008 for natural gas and oil, respectively.

If proved reserves had been calculated consistent with the pricing methodology in place at the end of last year (i.e. end of year price), the Company’s estimate of proved reserves would have been 897.2 BCFE.  Of this amount, 59% would be natural gas and 78% would be characterized as proved developed reserves.  The before income tax PV-10 of this scenario would be $2.4 billion, 90% of which relates to the proved developed reserves.

Below is a table detailing the Company’s costs incurred in oil and gas producing activities for the year ended December 31, 2009.  St. Mary invested 51% less in 2009 compared to 2008 and deployed 62% less in development activities year over year.


Costs incurred in oil and gas producing activities:
 
 
For the Year Ended
 
 
December 31,
 
 
2009
 
 
($ in thousands)
 
Development costs
$ 223,108  
Exploration costs
  154,122  
Acquisitions:
     
  Proved properties
  76  
  Unproved properties – acquisitions of
     
    proved properties
  -  
  Unproved properties – other
  41,677  
Total, including asset retirement obligation
$ 418,983  

 
FINANCIAL POSITION AND LIQUIDITY

As of December 31, 2009, St. Mary had total long-term debt of $454.9 million.  The long-term credit facility was down $47 million from September 30, 2009, to $188.0 million and the balance on the 3.50% Senior Convertible Notes was $266.9 million, net of debt discount.  The credit facility matures in July of 2012 and the Senior Convertible Notes cannot be put to the Company until April of 2012.  The Company’s debt-to-book capitalization ratio was 32% as of the end of the quarter.
 
6

 
The borrowing base for the long-term credit facility was reaffirmed by St. Mary’s bank group on September 29, 2009, and remains unchanged at an amount of $900 million.  The Company has a commitment amount of $678 million from the 12 banks that comprise the Company’s bank group.


OPERATIONAL UPDATE

Capital Investment Budget
There have been no significant changes to the 2010 capital budget of $725 million that was provided in the Company’s December 16, 2009, press release.

Eagle Ford Shale
St. Mary currently has 250,000 net acres leased or optioned in South Texas that are prospective for the Eagle Ford shale, which is an increase from the 225,000 net acres last reported.  The acreage is comprised of roughly 168,000 net acres in Webb and LaSalle counties where the Company has essentially 100% working interest and 82,500 net acres in a joint venture with Anadarko Petroleum in Dimmit County.

St. Mary has drilled and completed an additional 5 wells on its operated acreage since its last update.  The table below provides production and operational details regarding these recent Eagle Ford shale wells.


Name
7-day Max Sales (MMCFE/d)
30-day Max Sales (MMCFE/d)
BTU/SCF
Condensate Yield    (BPM)
Lateral Length
Completion Stages
Briscoe G 2H
9.1
6.6
1,300
32
4,995
15
Briscoe B 1H
7.6
4.8
1,300
29
5,044
15
Briscoe G GU 1 3H
5.8
3.7
1,280
39
5,035
15
Galvan Ranch 7H
6.7
5.6
1,160
0
5,031
15
Briscoe G 4H
8.0
N/A
1,260
102
5,050
15


The Company plans to operate two drilling rigs throughout 2010 and will drill 34 gross wells in its Eagle Ford program.  St. Mary also plans to participate in the partner-operated program on the joint venture acreage.

Marcellus Shale
In the Marcellus shale program in north central Pennsylvania, the Company expects wells drilled in the McKean County portion of its acreage to have initial production rates of between 3 to 5 MMCFE/d based on testing done to date.  A gathering line that will connect these first two wells to the sales pipeline, as well as serve future planned development, is currently under construction.  The connection to the first well has been completed and sales will commence when a temporary facility issue has been corrected.  The connection to the second well is expected to be completed around mid-year.

7
 
St. Mary has leased or optioned approximately 42,000 net acres in McKean and Potter Counties, Pennsylvania.  The Company plans to drill a total of four horizontal wells in 2010; two each in McKean and Potter Counties.  A seismic shoot over a portion of the acreage is also planned for this year.

Haynesville Shale
The 3D data for the Company’s acreage in Shelby and San Augustine Counties, Texas has been received and is currently being evaluated.  St. Mary has one operated rig drilling in East Texas targeting the Haynesville shale.  The Company has 41,000 net acres that it believes are prospective for the Haynesville shale, of which 31,000 net acres are located in Shelby and San Augustine Counties, Texas.  Much of the acreage in these counties is also believed to be prospective for the Bossier shale.

Seven operated horizontal wells targeting the Haynesville shale are planned for 2010, all of which will be on high working interest acreage in East Texas.

Woodford Shale
The two increased density simultaneous fracture stimulation (“simul-frac”) pilots that were conducted in 2009 have been concluded and analyzed, and the results are positive.  During 2009, the Company’s first test involved simul-fracing four wells on 128-acre spacing, or five wells per section.  Positive initial results from this test led to a four well test on 64-acre spacing, or ten wells per section.  The Company believes that it will be able to book proved reserves on these infill wells at a range of 2.7 to 3.0 BCFE per well, which is consistent with the range seen on lower density drilling.  St. Mary believes that the results learned from this effort will improve its understanding of the ultimate spacing in some other shale plays, particularly the Eagle Ford and Marcellus shales.

St. Mary has roughly 34,000 net acres in the Arkoma Basin in Oklahoma with potential for the Woodford shale.  The Company’s plan to drill six horizontal wells in 2010 is designed primarily to preserve its acreage position in the play.


Bakken/Three Forks
The Company recently completed a test designed to determine the connectivity of the Bakken and Three Forks formations in a portion of its acreage.  Two horizontal wells were drilled, with one targeting the Bakken and the other targeting the Three Forks.  These wells were then simul-fraced together.  The combined 24 hour IP of the two wells was roughly 2,800 BOEPD.   The Company will be monitoring the performance of the wells over a number of months to determine the extent to which the two wells may be producing incremental reserves beyond what could be obtained through a single zone completion. 

St. Mary has approximately 70,000 net acres in North Dakota that it believes are prospective for development of the Bakken and Three Forks intervals.  This is an increase of roughly 17,000 net acres from the end of 2008.  Approximately 48,000 net
 
8
 
acres are located in McKenzie and Williams counties.  The Company also has roughly 21,000 net acres in Divide County, North Dakota where testing is focused on the Three Forks interval.

The Company plans to drill 17 operated wells in the Williston Basin in 2010, the majority of which will be Bakken wells in its Bear Den prospect in McKenzie County.

Other Activity
In the Permian Basin, two operated rigs are currently running in the basin.  The Wolfberry tight oil program continues to be the primary focus of the Company in the basin.

The Company is currently drilling a horizontal Granite Wash well in its Mayfield area in Beckham County, Oklahoma.  St. Mary has roughly 32,000 net acres that are prospective for the Granite Wash interval, the majority of which is held by production.  Four operated wells are planned in this program for 2010.

St. Mary is engaged in an exploration program targeting the Niobrara formation in south eastern Wyoming.  The Company is currently in the process of drilling its first well.  St. Mary currently has 24,000 net acres under lease in the area.


2010 GUIDANCE

The Company’s guidance for the first quarter and the full year of 2010 is as follows:

 
1st Quarter
 
Full Year
 
Oil and gas production, reported
255 – 278 MMCFE/d
 
253 – 276 MMCFE/d
 
Lease operating expense
$1.40 – $1.45/MCFE
 
$1.33 – $1.38/MCFE
 
Transportation expense
$0.18 – $0.23/MCFE
 
$0.20 – $0.25/MCFE
 
Production taxes, as a percentage of pre-hedge oil & gas revenue
  7%     7%  
             
General and admin. – cash
$0.47 – $0.50/MCFE
 
$0.51 – $0.54/MCFE
 
General and admin. – cash NPP
$0.22 – $0.24/MCFE
 
$0.22 – $0.24/MCFE
 
General and admin. – non-cash
$0.15 – $0.17/MCFE
 
$0.18 – $0.20/MCFE
 
General and admin. – TOTAL
$0.84 – $0.91/MCFE
 
$0.91 – $0.98/MCFE
 
             
Depreciation, depletion, & amort.
$2.95 – $3.15/MCFE
 
$2.90 – $3.10/MCFE
 
Non-cash interest
$ 3.3 MM   $ 13.5 MM  
Effective tax rate
  37%     37%  
             

Production guidance for 2010 is unchanged from the information that was provided in the press release provided December 16, 2010.  As reported in that release, production is anticipated to decline sequentially in the first half of 2010 due primarily to previously
 
9
 
announced divestitures, which results in higher per unit costs for costs that have a larger component of fixed costs.

Beginning with this press release, the Company is breaking down its general and administrative expense into three components.  The G&A – cash line item is for items such as salaries, office, and general corporate expenses that will be paid in cash and that the Company can be reasonably expected to control and forecast.  The G&A – cash NPP line relates to cash payments from St. Mary’s legacy Net Profits Plan.  These payments are tied to the net revenues generated by properties in associated pools.  Over time the proved reserves associated with these profit pools will produce out and payments from this program can be expected to go down directionally over time, absent the impact of commodity prices.  Net revenues are directly related to commodity prices, which causes this line item to be difficult to forecast with a high degree of accuracy.  The G&A – non-cash line is related to the amortization of stock compensation.  St. Mary’s current long-term equity incentive program began in 2008 and involves awards that vest over three years.  Each annual award to employees for the last two years has resulted in a new layer of stock compensation that amortizes over a three year life for the respective grant.  With the 2010 annual award, a third layer will be added for G&A stock compensation.  Going forward there will be three grant years amortizing through the income statement since the expense related to future awards will be offset by awards from prior year awards becoming fully amortized after three years.

A summary of the Company’s current hedge position is included in the appendix in the investor relations presentation that will supplement the Company’s earnings call schedule for February 23, 2010.  The presentation can be found in the Investor Relations section of the Company’s website at stmaryland.com.


EARNINGS CALL INFORMATION

The Company has scheduled a teleconference to discuss the fourth quarter results on February 23, 2010, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time).  The call participation number is 877-265-4451 and the conference number is 50355324.  An audio replay of the call will be available approximately two hours after the call at 800-642-1687, conference number 50355324.  International participants can dial 702-928-6464  to take part in the conference call and can access a replay of the call at 706-645-9291, conference number 50355324.  Replays can be accessed through March 9, 2010.

In addition, the call will be webcast live and can be accessed at St. Mary’s web site at stmaryland.com.  An audio recording of the conference call will be available at that site through March 9, 2010.

A presentation to be referred to during the earnings call will be available on the home page of St. Mary’s website at stmaryland.com prior to the earnings call.

10

 
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,” “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, the pending nature of reported divestiture plans for certain non-core oil and gas properties as well as the ability to complete divestiture transactions and the uncertain nature of the amount of proceeds that may be received from divestitures, 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 2009 Annual Report on Form 10-K, which is anticipated to be filed on or about February 23, 2010.  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.


ABOUT THE COMPANY

St. Mary Land & Exploration Company is an independent energy company engaged  in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil.  St. Mary routinely posts important information about the Company on its website.  For more information about St. Mary, please visit its website at stmaryland.com.

11
 
 
 



ST. MARY LAND & EXPLORATION COMPANY
 
FINANCIAL HIGHLIGHTS
 
December 31, 2009
 
                         
                         
Production Data
For the Three Months
     
For the Years
     
 
Ended December 31,
     
Ended December 31,
     
 
2009
 
2008
 
Percent
 Change
 
2009
 
2008
 
Percent
 Change
 
                         
Average realized sales price, before hedging:
                       
Oil (per Bbl)
$ 68.98   $ 50.17   37%   $ 54.40   $ 92.99   -41%  
Gas (per Mcf)
  4.88     5.30   -8%     3.82     8.60   -56%  
                                 
Average realized sales price, net of hedging:
                               
Oil (per Bbl)
$ 64.43   $ 55.63   16%   $ 56.74   $ 75.59   -25%  
Gas (per Mcf)
  6.07     7.09   -14%     5.59     8.79   -36%  
                                 
Production:
                               
Oil (MMBbls)
  1.5     1.7   -12%     6.3     6.6   -4%  
Gas (Bcf)
  17.1     19.7   -13%     71.1     74.9   -5%  
BCFE (6:1)
  26.1     30.0   -13%     109.1     114.6   -5%  
                                 
Daily production:
                               
Oil (MBbls per day)
  16.4     18.7   -12%     17.3     18.1   -4%  
Gas (MMcf per day)
  185.3     213.8   -13%     194.8     204.7   -5%  
MMCFE per day (6:1)
  284.0     326.0   -13%     298.8     313.1   -5%  
                                 
Margin analysis per MCFE:
                               
Average realized sales price, before hedging
$ 7.18   $ 6.35   13%   $ 5.65   $ 10.99   -49%  
                                 
Average realized sales price, net of hedging
  7.69     7.84   -2%     6.94     10.11   -31%  
Lease operating expense
  1.31     1.59   -18%     1.33     1.46   -9%  
Transportation
  0.20     0.20   0%     0.19     0.19   0%  
Production taxes
  0.51     0.39   31%     0.37     0.71   -48%  
General and administrative
  0.80     0.41   95%     0.70     0.69   1%  
Operating margin
$ 4.87   $ 5.25   -7%   $ 4.35   $ 7.06   -38%  
Depletion, depreciation, amortization, and
                               
asset retirement obligation liability accretion
$ 2.88   $ 3.18   -9%   $ 2.79   $ 2.74   2%  

 
 
 

ST. MARY LAND & EXPLORATION COMPANY
 
FINANCIAL HIGHLIGHTS
 
December 31, 2009
 
                 
                 
NOTE: On January 1, 2009, new authoritative accounting guidance under FASB ASC Topic 470-20, “Debt with Conversion and Other Options” (“ASC Topic
 
470") required retrospective application. As a result, prior period balances presented have been adjusted to reflect the period-specific effects of applying
 
ASC Topic 470
               
                 
Consolidated Statements of Operations
               
(In thousands, except per share amounts)
For the Three Months
 
For the Years
 
 
Ended December 31,
 
Ended December 31,
 
    2009     2008     2009     2008  
       
(As adjusted)
       
(As adjusted)
 
Operating revenues and other income:
                       
Oil and gas production revenue
$ 187,606   $ 190,499   $ 615,953   $ 1,259,400  
Realized oil and gas hedge gain (loss)
  13,418     44,741     140,648     (101,096 )
Marketed gas system revenue
  16,977     11,935     58,459     77,350  
Gain on divestiture activity
  22,076     9,494     11,444     63,557  
Other revenue
  1,919     1,500     5,697     2,090  
Total operating revenues and other income
  241,996     258,169     832,201     1,301,301  
                         
Operating expenses:
                       
Oil and gas production expense
  52,872     65,530     206,800     271,355  
Depletion, depreciation, amortization,
                       
and asset retirement obligation liability accretion
  75,140     95,260     304,201     314,330  
Exploration
  13,414     17,743     62,235     60,121  
Impairment of proved properties
  21,630     292,100     174,813     302,230  
Abandonment and impairment of unproved properties
  25,153     34,754     45,447     39,049  
Impairment of materials inventory
  774     -     14,223     -  
Impairment of goodwill
  -     9,452     -     9,452  
General and administrative
  20,687     12,354     76,036     79,503  
Bad debt expense (recovery)
  (5,189 )   143     (5,189 )   16,735  
Change in Net Profits Plan liability
  6,963     (80,941 )   (7,075 )   (34,040 )
Marketed gas system expense
  16,235     11,241     57,587     72,159  
Unrealized derivative (gain) loss
  3,218     (12,011 )   20,469     (11,209 )
Other expense
  1,065     1,260     13,489     10,415  
Total operating expenses
  231,962     446,885     963,036     1,130,100  
                         
Income (loss) from operations
  10,034     (188,716 )   (130,835 )   171,201  
                         
Nonoperating income (expense):
                       
Interest income
  10     90     227     485  
Interest expense
  (7,532 )   (6,088 )   (28,856 )   (26,950 )
                         
Income (loss) before income taxes
  2,512     (194,714 )   (159,464 )   144,736  
Income tax benefit (expense)
  (1,522 )   67,622     60,094     (57,388 )
                         
Net income (loss)
$ 990   $ (127,092 ) $ (99,370 ) $ 87,348  
                         
Basic weighted-average common shares outstanding
  62,565     62,212     62,457     62,243  
                         
Diluted weighted-average common shares outstanding
  64,113     62,212     62,457     63,133  
                         
Basic net income (loss) per common share
$ 0.02   $ (2.04 ) $ (1.59 ) $ 1.40  
                         
Diluted net income (loss) per common share
$ 0.02   $ (2.04 ) $ (1.59 ) $ 1.38  

 
 
 


ST. MARY LAND & EXPLORATION COMPANY
 
FINANCIAL HIGHLIGHTS
 
December 31, 2009
 
         
         
Consolidated Balance Sheets
       
(In thousands, except share amounts)
December 31,
 
December 31,
 
ASSETS
2009
 
2008
 
     
(As adjusted)
 
Current assets:
       
Cash and cash equivalents
$ 10,649   $ 6,131  
Short-term investments
  -     1,002  
Accounts receivable, net of allowance for doubtful accounts
       
of $- in 2009 and $16,788 in 2008
  116,136     157,690  
Refundable income taxes
  32,773     13,161  
Prepaid expenses and other
  14,259     22,161  
Derivative asset
  30,295     111,649  
Deferred income taxes
  4,934     -  
Total current assets
  209,046     311,794  
             
Property and equipment (successful efforts method), at cost:
       
Land
  1,371     1,350  
Proved oil and gas properties
  2,797,341     2,969,722  
Less - accumulated depletion, depreciation, and amortization
  (1,053,518 )   (947,207 )
Unproved oil and gas properties, net of impairment allowance
       
of $66,570 in 2009 and $42,945 in 2008
  132,370     168,817  
Wells in progress
  65,771     90,910  
Materials inventory, at lower of cost or market
  24,467     40,455  
Oil and gas properties held for sale less accumulated depletion,
       
depreciation, and amortization
  145,392     1,827  
Other property and equipment, net of accumulated depreciation
       
of $14,550 in 2009 and $13,848 in 2008
  14,404     13,458  
    2,127,598     2,339,332  
             
Other noncurrent assets:
           
Derivative asset
  8,251     21,541  
Restricted cash subject to Section 1031 Exchange
  -     14,398  
Other noncurrent assets
  16,041     10,182  
Total other noncurrent assets
  24,292     46,121  
             
Total Assets
$ 2,360,936   $ 2,697,247  
             
LIABILITIES AND STOCKHOLDERS' EQUITY
       
             
Current liabilities:
           
Accounts payable and accrued expenses
$ 236,242   $ 254,811  
Derivative liability
  53,929     501  
Deposit associated with oil and gas properties held for sale
  6,500     -  
Deferred income taxes
  -     41,289  
Total current liabilities
  296,671     296,601  
             
Noncurrent liabilities:
           
Long-term credit facility
  188,000     300,000  
Senior convertible notes, net of unamortized
           
discount of $20,598 in 2009, and $28,787 in 2008
  266,902     258,713  
Asset retirement obligation
  60,289     108,755  
Asset retirement obligation associated with oil and gas properties held for sale
  18,126     238  
Net Profits Plan liability
  170,291     177,366  
Deferred income taxes
  308,189     354,328  
Derivative liability
  65,499     27,419  
Other noncurrent liabilities
  13,399     11,318  
Total noncurrent liabilities
  1,090,695     1,238,137  
             
Commitments and contingencies
           
             
Stockholders' equity:
           
Common stock, $0.01 par value: authorized - 200,000,000 shares;
       
issued: 62,899,122 shares in 2009 and 62,465,572 shares in 2008;
 
outstanding, net of treasury shares: 62,772,229 shares in 2009
       
and 62,288,585 shares in 2008
  629     625  
Additional paid-in capital                          
  160,516     141,283  
Treasury stock, at cost:  126,893 shares in 2009 and 176,987 shares in 2008
  (1,204 )   (1,892 )
Retained earnings
  851,583     957,200  
Accumulated other comprehensive income (loss)
  (37,954 )   65,293  
Total stockholders' equity
  973,570     1,162,509  
             
Total Liabilities and Stockholders' Equity
$ 2,360,936   $ 2,697,247  

 
 
 

ST. MARY LAND & EXPLORATION COMPANY
 
FINANCIAL HIGHLIGHTS
 
December 31, 2009
 
                 
                 
Consolidated Statements of Cash Flows
               
(In thousands)
For the Three Months
 
For the Years
 
 
Ended December 31,
 
Ended December 31,
 
 
2009
 
2008
 
2009
 
2008
 
Cash flows from operating activities:
   
(As adjusted)
     
(As adjusted)
 
                 
Net income (loss)
$ 990   $ (127,092 ) $ (99,370 ) $ 87,348  
Adjustments to reconcile net income (loss) to net cash
                   
provided by operating activities:
                       
Gain on divestiture activities
  (22,076 )   (9,494 )   (11,444 )   (63,557 )
Depletion, depreciation, amortization,
                       
and asset retirement obligation liability accretion
  75,140     95,260     304,201     314,330  
Exploratory dry hole expense
  2,961     240     7,810     6,823  
Impairment of proved properties
  21,630     292,100     174,813     302,230  
Abandonment and impairment of unproved properties
  25,153     34,754     45,447     39,049  
Impairment of materials inventory
  774     -     14,223     -  
Impairment of goodwill
  -     9,452     -     9,452  
Stock-based compensation expense*
  5,787     4,335     18,765     14,812  
Bad debt expense (recovery)
  (5,189 )   143     (5,189 )   16,735  
Change in Net Profits Plan liability
  6,963     (80,941 )   (7,075 )   (34,040 )
Unrealized derivative (gain) loss
  3,218     (12,011 )   20,469     (11,209 )
Loss related to hurricanes
  28     -     8,301     6,980  
Loss on insurance settlement
  -     696     -     2,296  
Amortization of debt discount and deferred financing costs
  3,291     2,402     12,213     9,344  
Deferred income taxes
  29,347     (61,216 )   (39,735 )   38,164  
Plugging and abandonment
  (14,286 )   (7,813 )   (26,396 )   (9,168 )
Other
  1,950     7,291     3,382     3,875  
Changes in current assets and liabilities:
                       
Accounts receivable
  (12,101 )   25,128     46,743     (14,327 )
Refundable income taxes
  (29,952 )   (8,578 )   (19,612 )   (12,228 )
Prepaid expenses and other
  2,034     (3,533 )   (6,626 )   (1,504 )
Accounts payable and accrued expenses
  (12,608 )   (47,111 )   (4,814 )   (12,348 )
Excess income tax benefit from the exercise of stock options
  -     (3,586 )   -     (13,867 )
Net cash provided by operating activities
  83,054     110,426     436,106     679,190  
                         
Cash flows from investing activities:
                       
Proceeds from insurance settlement
  1,453     -     16,789     -  
Proceeds from sale of oil and gas properties
  38,761     23,664     39,898     178,867  
Capital expenditures
  (86,787 )   (251,431 )   (379,253 )   (746,586 )
Acquisition of oil and gas properties
  (18 )   1,610     (76 )   (81,823 )
Receipts from restricted cash
  -     -     14,398     -  
Deposits to restricted cash
  -     (14,398 )   -     (14,398 )
Receipts from short-term investments
  -     9     1,002     170  
Other
  3,150     -     3,150     (9,984 )
Net cash used in investing activities
  (43,441 )   (240,546 )   (304,092 )   (673,754 )
                         
Cash flows from financing activities:
                       
Proceeds from credit facility
  174,000     1,739,500     2,072,500     2,571,500  
Repayment of credit facility
  (221,000 )   (1,609,500 )   (2,184,500 )   (2,556,500 )
Debt issuance costs related to credit facility
  -     -     (11,074 )   -  
Excess income tax benefit from the exercise of stock options
  -     3,586     -     13,867  
Proceeds from sale of common stock
  1,931     561     3,110     11,888  
Repurchase of common stock
  -     -     -     (77,202 )
Dividends paid
  (3,127 )   (3,110 )   (6,247 )   (6,186 )
Other
  (1,285 )   (182 )   (1,285 )   (182 )
Net cash provided by (used in) financing activities
  (49,481 )   130,855     (127,496 )   (42,815 )
                         
Net change in cash and cash equivalents
  (9,868 )   735     4,518     (37,379 )
Cash and cash equivalents at beginning of period
  20,517     5,396     6,131     43,510  
Cash and cash equivalents at end of period
$ 10,649   $ 6,131   $ 10,649   $ 6,131  
                         
* 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, 2009,and 2008, respectively, approximately $1.9 million and $2.0 million of stock based compensation was
 
included in exploration expense. For the years ended December 31, 2009, and 2008, respectively, approximately $6.3 million and $5.8 million of stock-based
 
compensation expense was included in exploration expense. For the three months ended December 31, 2009, and 2008, respectively, approximately $3.9 million
 
and $2.3 million of stock-based compensation was included in general and administrative expense. For the years ended December 31, 2009, and 2008,
 
respectively approximately $12.5 million and $9.0 million of stock-based compensation expense was included in general and administrative expense.
 

 
 
 

ST. MARY LAND & EXPLORATION COMPANY
 
FINANCIAL HIGHLIGHTS
 
December 31, 2009
 
                 
                 
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,
 
 
2009
 
2008
 
2009
 
2008
 
     
(As adjusted)
   
(As adjusted)
                 
Reported Net Income (Loss) (GAAP)
$ 990   $ (127,092 ) $ (99,370 ) $ 87,348  
                         
Adjustments net of tax:
                       
Change in Net Profits Plan liability
  4,338     (52,831 )   (4,409 )   (20,543 )
Unrealized derivative (gain) loss
  2,005     (7,840 )   12,755     (6,765 )
Gain on divestiture activities
  (13,753 )   (6,197 )   (7,131 )   (38,357 )
Bad debt expense (recovery) associated with Sem Group, L.P.
  (3,143 )   (3 )   (3,143 )   10,039  
Loss related to hurricanes (1)
  17     -     5,173     4,212  
Loss on insurance settlement
  -     454     -     1,386  
                         
Adjusted Net Income (Loss), before impairment adjustments
  (9,546 )   (193,509 )   (96,125 )   37,320  
                         
Non-cash impairments net of tax:
                       
Impairment of proved properties
  13,475     190,657     108,935     182,395  
Abandonment and impairment of unproved properties
  15,670     22,684     28,320     23,566  
Impairment of goodwill
  -     6,169     -     5,704  
Impairment of materials inventory
  482     -     8,863     -  
Adjusted Net Income, non-recurring items
                       
& non-cash impairments (Non-GAAP) (2)
$ 20,081   $ 26,001   $ 49,993   $ 248,985  
                         
Adjusted Net Income Per Share (Non-GAAP)
                       
Basic
$ 0.32   $ 0.42   $ 0.80   $ 4.00  
Diluted
$ 0.31   $ 0.42   $ 0.80   $ 3.94  
                         
Average Number of Shares Outstanding
                       
Basic
  62,565     62,212     62,457     62,243  
Diluted
  64,113     62,212     62,457     63,133  
                         
                         
(1)    The loss related to hurricanes is included within line item other expense on the consolidated statements of operations.
                         
(2)   Adjusted net income is calculated as net income (loss) adjusted for significant non-cash and non-recurring items. Non-cash charges and adjustments include
change in the Net Profits Plan liability, unrealized derivative (gain) loss, impairment of proved properties, abandonment and impairment of unproved
properties, impairment of goodwill, and impairment of materials inventory. Non-recurring items include gain on divestiture activities, loss related to 
hurricanes, loss on insurance settlement, and bad debt expense (recovery) associated with Sem Group, L.P. 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,
 
   
2009
   
2008
   
2009
   
2008
 
           (As adjusted)              
Net cash provided by operating activities (GAAP)
 83,054
  $
110,426
  $
436,106
 
 679,190
 
                         
Changes in current assets and liabilities
 
                    52,627
   
                 37,680
   
                    (15,691
 
                    54,274
 
                         
Exploration
 
                    13,414
   
                 17,743
   
                     62,235
   
                    60,121
 
      Less:  Exploratory dry hole expense
 
                     (2,961
 
                     (240)
   
                      (7,810
 
                     (6,823
      Less:  Stock-based compensation expense included in exploration
 
                     (1,917
 
                  (1,992)
   
                      (6,314
 
                     (5,799
                         
Discretionary cash flow (Non-GAAP) (3)
 144,217
 
163,617
  $
468,526
 
 780,963
 
                         
                         
(3)   Beginning in the third quarter of 2009 the Company changed its definition of discretionary 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 definiton. Discretionary 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 discretionary cash flow is presented because 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, 2009
 
                     
                     
Information on Reserves and Costs Incurred
                 
                     
Costs incurred in oil and gas producing activities:
                 
   For the Year Ended
 
             
 
December 31,
               
 
2009
               
Development costs
$ 223,108                
Exploration costs
  154,122                
Acquisitions:
                     
Proved properties
  76                
Unproved properties - acquisitions of
                     
proved properties (4)
  -                
Unproved properties - other
  41,677                
Total, including asset retirement obligation (5) (6)
$ 418,983                
                       
(4) Represents the allocated purchase price of unproved properties acquired as part of the acquisition of proved properties.
(5) Includes capitalized interest of $1.9 million for the year ended December 31, 2009.
         
(6) Includes amounts relating to estimated asset retirement obligations of $(805,000) for the year ended December 31, 2009.
                       
Proved oil and gas reserve quantities:
                     
 
For the Year Ended
 
 
December 31, 2009
 
 
Oil or Condensate
 
Gas
 
Equivalents
Proved 
Developed
Proved 
Undeveloped
 
(MMBbl)
 
(Bcf)
 
(BCFE)
 
(BCFE)
 
(BCFE)
 
Total proved reserves
                     
Beginning of year
  51.4     557.4     865.5     715.8     149.7  
Revisions of previous estimate
  4.5     (76.8 )   (49.6 )   (23.8 )   (25.8 )
Discoveries and extensions
  3.4     51.9     72.3     38.0     34.3  
Infill reserves in an existing proved field
  1.2     29.9     37.3     28.0     9.3  
Purchases of minerals in place
  -     -     -     -     -  
Sales of reserves
  (0.4   (41.8 )   (44.2 )   (37.2 )   (7.0 )
Production
  (6.3   (71.1 )   (109.1 )   (109.1 )   -  
Conversions
                    18.6     (18.6 )
End of year
  53.8     449.5     772.2     630.3     141.9  
                               
PV-10 value (in millions)
            $ 1,284.1   $ 1,253.1   $ 31.0  
                               
Proved developed reserves
                             
Beginning of year
  47.1     433.2     715.8              
End of year
  48.0     342.0     630.3              
                               
                               
Finding Cost and Reserve Replacement Ratios: (7)
                             
                               
Finding Costs in $ per MCFE
                             
Drilling, excluding revisions
$ 3.44                          
Drilling, including revisions
$ 6.29                          
All-in
$ 6.99                          
                               
Reserve Replacement Ratios
                             
Drilling, excluding revisions
  100%                          
Drilling, including  revisions
  55%                          
All-in
  55%                          
                               
(7) 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 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 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.

The following information was filed by Sm Energy Co (SM) on Tuesday, February 23, 2010 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-K Annual Report statement of earnings and operation as management may choose to highlight particular information in the press release.

View differences made from one year to another to evaluate Sm Energy Co's financial trajectory

Compare SEC Filings Year-over-Year (YoY) and Quarter-over-Quarter (QoQ)
Sample 10-K Year-over-Year (YoY) Comparison

Compare this 10-K Annual Report to its predecessor by reading our highlights to see what text and tables were  removed  ,   added    and   changed   by Sm Energy Co.

Continue

Never Miss A New SEC Filing Again


Real-Time SEC Filing Notifications
Screenshot taken from Gmail for a new 10-K Annual Report
Last10K.com Member Feature

Receive an e-mail as soon as a company files an Annual Report, Quarterly Report or has new 8-K corporate news.

Continue

We Highlighted This SEC Filing For You


SEC Filing Sentiment Analysis - Bullish, Bearish, Neutral
Screenshot taken from Wynn's 2018 10-K Annual Report
Last10K.com Member Feature

Read positive and negative remarks made by management in their entirety without having to find them in a 10-K/Q.

Continue

Widen Your SEC Filing Reading Experience


Increased Reading Area for SEC Filings
Screenshot taken from Adobe Inc.'s 10-Q Quarterly Report
Last10K.com Member Feature

Remove data columns and navigations in order to see much more filing content and tables in one view

Continue

Uncover Actionable Information Inside SEC Filings


SEC Filing Disclosures
Screenshot taken from Lumber Liquidators 10-K Annual Report
Last10K.com Member Feature

Read both hidden opportunities and early signs of potential problems without having to find them in a 10-K/Q

Continue

Adobe PDF, Microsoft Word and Excel Downloads


Download Annual and Quarterly Reports as PDF, Word and Excel Documents
Screenshots of actual 10-K and 10-Q SEC Filings in PDF, Word and Excel formats
Last10K.com Member Feature

Export Annual and Quarterly Reports to Adobe PDF, Microsoft Word and Excel for offline viewing, annotations and analysis

Continue

FREE Financial Statements


Download Annual and Quarterly Reports as PDF, Word and Excel Documents
Screenshot of actual balance sheet from company 10-K Annual Report
Last10K.com Member Feature

Get one-click access to balance sheets, income, operations and cash flow statements without having to find them in Annual and Quarterly Reports

Continue for FREE

Intrinsic Value Calculator


Intrinsic Value Calculator
Screenshot of intrinsic value for AT&T (2019)
Last10K.com Member Feature

Our Intrinsic Value calculator estimates what an entire company is worth using up to 10 years of financial ratios to determine if a stock is overvalued or not

Continue

Financial Stability Report


Financial Stability Report
Screenshot of financial stability report for Coco-Cola (2019)
Last10K.com Member Feature

Our Financial Stability reports uses up to 10 years of financial ratios to determine the health of a company's EPS, Dividends, Book Value, Return on Equity, Current Ratio and Debt-to-Equity

Continue

Get a Better Picture of a Company's Performance


Financial Ratios
Available Financial Ratios
Last10K.com Member Feature

See how over 70 Growth, Profitability and Financial Ratios perform over 10 Years

Continue

Log in with your credentials

or    

Forgot your details?

Create Account