News Release

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SM Energy Reports Third Quarter of 2015 Results - Exceeding Expectations for 2015 Through Efficiencies and Performance
  • Produced 16.1 million barrels of oil equivalent (MMBOE), up 22% from the prior year period and above plan
  • Realized $259.4 million adjusted EBITDAX (see GAAP reconciliations below), exceeding the Company's expectations
  • Maintained modest debt to adjusted TTM EBITDAX at 1.9 times
  • Monitored 130 days of success with Eagle Ford Pilot Test #1, which supports downspacing in Eagle Ford East
  • Achieving substantial progress in well performance and cost efficiencies

DENVER--(BUSINESS WIRE)--Oct. 27, 2015-- SM Energy Company (NYSE: SM) announces its financial results for the third quarter of 2015 and provides an operations update. In conjunction with this release, the Company posted an investor presentation with additional third quarter earnings and operations detail to the Company's website at www.sm-energy.com. This presentation will be referenced during the conference call scheduled for 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on October 28, 2015. Information for the call can be found below.

MANAGEMENT COMMENTARY

Comments from President and Chief Executive Officer Jay Ottoson: "I am pleased to report another excellent quarter with production and EBITDAX that exceeded our internal forecasts. Third quarter production was up sequentially from the second quarter (adjusted for assets sold in the second quarter) and up 22% compared with the third quarter last year.

"Operational execution continues to drive our outperformance. We are working hard to reduce costs and apply technology effectively on a number of fronts. We are reducing drilling times, optimizing completions and generating better well results in our core development programs. For example, drilling and completion costs for our operated Eagle Ford wells in the third quarter were down nearly 50% from our 2014 average. At the same time, we have been conducting several pilot tests in high productivity areas of the Eagle Ford and Bakken/Three Forks intended to prove up additional economic drilling inventory. Test results to date have been positive and have translated into higher than forecast production.

"Looking into 2016, we plan to focus our activity on our programs that generate the best returns. Our diligent efforts to reduce costs and improve well performance will continue, and we expect to allocate an increased portion of capital to the Permian and Williston Basins. Fundamental to the 2016 operating plan will be aligning capital spending with estimated EBITDAX to optimize cash flow and inventory expansion, resulting in differential value creation in 2016."

THIRD QUARTER 2015 RESULTS

Production for the third quarter of 2015 was 16.1 MMBOE, or 174.5 MBOE/d, up 22% compared with 13.1 MMBOE, or 142.5 MBOE/d, in the third quarter of 2014. Total production increased sequentially, adjusted for second quarter assets sales, and exceeded the Company's expectations by approximately 0.6 MMBOE, despite an 11% sequential decline in non-operated Eagle Ford production.

Strong production was driven by well performance in the Company's core areas that continues to exceed the Company's year-end 2014 type curves plus a number of positive test wells in the Eagle Ford that came on sales during the quarter. Specifically, Eagle Ford Test #1 reached a peak natural gas rate of 105 MMcf/d during the quarter and Test #3 is on sales with several wells producing more than 10 MMcf/d each, while still cleaning up. Of note, these tests were drilled in high natural gas content areas, increasing the mix of natural gas in total third quarter production. The production mix for the quarter was 28% oil, 45% natural gas and 27% natural gas liquids ("NGLs"). For the first nine months of 2015, total production was 49.3 MMBOE, up 27% compared with 39.0 MMBOE in the first nine months of 2014.

Sequential Production

     
Production 3Q15 2Q15*
 
Oil Production (MMBbls) 4.5 5.1
Gas Production (Bcf) 43.3 40.3
NGL Production (MMBbls) 4.3   4.0
Total Production (MMBOE) 16.1 15.8
 
Equivalent Daily Production (MBOE/d) 174.5 173.6
 

*2Q15 production adjusted for asset sales completed during that quarter.

 

Pricing in the third quarter of 2015 reflected a 52% decline in WTI oil prices, a 30% decline in NYMEX natural gas prices and a 54% decline in OPIS NGL prices from the prior year period. The Company had approximately 48% of oil production, 34% of natural gas production and 40% of NGL production hedged during the quarter. The table below provides the average realized prices received by product, as well as the adjusted prices received after taking into account settlements for derivative transactions:

Average Realized Commodity Prices for the Three Months Ended September 30, 2015

   

Before the effect of
derivative settlements

 

After the effect of
derivative settlements

 
Oil ($/Bbl) $40.03 $60.05
Gas ($/Mcf) $2.77 $3.22
Natural gas liquids ($/Bbl) $15.18 $16.12
Equivalent ($/BOE) $22.84 $29.92
 

Operating costs in the third quarter of 2015 included lease operating expenses of $3.86 per BOE, down $0.72 per BOE from the prior year period, and transportation expenses of $6.27 per BOE, up $0.05 per BOE from the prior year period. Lease operating expenses on the Company’s operated properties tracked internal forecasts and included planned higher workover expenses compared with the second quarter of 2015. Third quarter lease operating expenses at the Company’s non-operated Eagle Ford properties increased Company-wide lease operating expenses $0.20 per BOE sequentially. For the first nine months of 2015, lease operating expenses averaged $3.70 per BOE and transportation costs averaged $5.99 per BOE, down 13% and 4%, respectively.

General and administrative expenses for the third quarter of 2015 were $37.8 million, or $2.35 per BOE. Net of non-cash compensation expenses of $5.4 million, general and administrative expenses were $32.4 million, or $2.02 per BOE. General and administrative expenses per BOE were down significantly compared with the prior year periods, down 26% in the third quarter and down 15% in the first nine months.

Net income for the third quarter of 2015 was $3.1 million, or $0.05 per diluted common share, compared with net income of $208.9 million, or $3.05 per diluted common share, in the third quarter of 2014. For the first nine months of 2015, the Company's net loss was $107.5 million, or $1.59 per diluted common share, compared with net income of $334.3 million, or $4.90 per diluted common share, in the prior year period.

Adjusted net loss for the third quarter of 2015 was $23.3 million, or $0.34 per diluted common share, compared with adjusted net income of $98.6 million, or $1.44 per diluted common share, in the third quarter of 2014. Lower adjusted net income is predominantly due to the 51% decline in average prices received per BOE, partially offset by the 22% increase in production and 15% decrease in production costs per BOE. Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and are generally items whose timing and/or amount cannot be reasonably estimated.

Adjusted earnings before interest, taxes, depletion, amortization and accretion, and exploration expense, or adjusted EBITDAX, was $259.4 million for the third quarter of 2015, compared with $406.2 million in the third quarter of 2014. Lower adjusted EBITDAX is primarily a result of significantly lower commodity prices in the third quarter of 2015, partially offset by higher production and lower costs per BOE, as discussed above.

Adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the Financial Highlights section at the end of this release for additional information about these measures.

CAPITAL, OPERATIONS AND GUIDANCE

Capital Expenditures

The Company’s total 2015 capital expenditures are estimated at approximately $1.28 billion. Capital expenditures through the first nine months totaled approximately $1.1 billion.

The Company's 2015 drilling program is primarily focused on its Eagle Ford shale and Bakken/Three Forks plays. Third quarter of 2015 capital expenditures were $277 million, down approximately 18% from the second quarter of 2015, as the Company reduced its drilling activity from nine rigs at the end of the second quarter to seven rigs currently. The Company's seven active operated rigs include four in the Eagle Ford, two in the Bakken/Three Forks and one in the Powder River Basin. At year-end, the Company anticipates releasing one rig from its Eagle Ford program and adding one rig in the Permian Basin. The Company is currently deferring most completions in both its Eagle Ford and Bakken/Three Forks programs and plans to increase completion activity around year-end.

Eagle Ford

Third quarter of 2015 net production averaged 134.5 BOE/d, including both operated and non-operated wells. Daily production increased 31% from the third quarter of 2014 and increased 3% sequentially from the second quarter of 2015, despite an 11% sequential decline in non-operated production from the area.

The focus on operational execution in the operated Eagle Ford is resulting in a number of quantifiable results. For example, comparison of third quarter of 2015 data with 2014 full year averages shows a 54% decline in completion costs per lateral foot and a 28% reduction in drilling costs per lateral foot. The average days from spud-to-rig release per 1,000 feet of total measured depth improved approximately 14% in the program.

The Company has scheduled nine Eagle Ford multi-well pilot tests intended to test the potential for inventory expansion across its acreage position through downspacing, infill drilling and the addition of the Upper Eagle Ford interval. Wells have been drilled and completed in five of the nine tests, with the remaining tests expected to be completed in 2016. To date, Eagle Ford test results are encouraging. On Test #1, a 14-well test of downspacing to 450 feet, the Company has approximately 130 days of sales. This successful test to date provides the Company with confidence that future drilling programs in the East Area can support 450 foot well-spacing. Test #3, a 5-well test of the Upper and Lower Eagle Ford intervals, includes 312 foot plan-view spacing. While this test is in a dry natural gas area, its broader implications are important as to date it appears to extend the footprint of the Company's Upper Eagle Ford to the south and support the potential for higher density plan-view spacing throughout the Company's 250-350 foot thick Eagle Ford shale position. Tests #2 through #5 are completed and either on flowback or have too few days of production to report.

Bakken/Three Forks

Third quarter of 2015 production from the Company's Bakken/Three Forks program averaged 22.2 MBOE/d and was 85% oil. Production increased 27% from the third quarter of 2014 and decreased 7% sequentially, as the Company continues to actively drill in the area but not complete all wells drilled. As of the end of the third quarter of 2015, the Company had an inventory of 47 gross and 39 net operated wells drilled and uncompleted in the area.

The Company's operations have focused on drilling and completion efficiencies. Drilling days in 2015 are down 11% on average from 2014 and the Company recently drilled a Divide County Bakken well, spud to rig release, in 10 days. Enhanced completions are driving 20%-30% increased recoveries per well as the Company employs plug-and-perf/cemented liner completions. Overall, costs in the area have been reduced by 20%-25% per well compared with similar wells in 2014.

Cumulative production from nine wells in Divide County, North Dakota testing the Bakken interval continues to perform above the Company's type curve expectations for the Three Forks interval, demonstrating the economic viability of Bakken locations in the area. Two additional Bakken wells were recently completed farther south on the Company's acreage, which could expand the potential of the Bakken interval to the south. The addition of the Bakken interval has the potential to significantly increase the Company's proved reserves and the inventory of drilling locations in Divide County.

Guidance

The Company has slightly modified full year 2015 guidance to narrow certain ranges. In addition, the Company has slightly increased the mid-point of production guidance and has slightly lowered the mid-point of transportation and ad valorem tax cost guidance. The following table presents updated production and performance guidance for full year 2015:

   
Revised Guidance for 2015
FY2015
Production (MMBOE) 63.6 - 64.4
Average daily production (MBOE/d) 174 - 176
 
LOE ($/BOE) $3.70 - $3.90
Ad Valorem ($/BOE) $0.45 - $0.50
Transportation ($/BOE) $6.10 - $6.25
Production taxes (% of pre-derivative oil, gas, and NGL revenue) 4.5% - 5.0%
 
G&A - Cash ($/BOE) $2.40 - $2.70
G&A - Non-cash ($/BOE) $0.30 - $0.40
Total G&A ($/BOE) $2.70 - $3.10
 
DD&A ($/BOE) $13.75 - $14.25
 
Effective income tax rate range 39.6% - 40.6%
 

FINANCIAL POSITION AND LIQUIDITY

The Company ended the third quarter of 2015 with long-term debt of $2.53 billion, including $2.35 billion in senior notes and $0.18 billion drawn on its revolving credit facility. As previously reported, under the Company’s credit facility, the borrowing base is $2.0 billion and aggregate commitments are $1.5 billion, providing the Company with ample liquidity.

The Company has commodity derivative contracts in place for the fourth quarter of 2015 representing approximately 43% of oil, 45% of natural gas and 48% of NGL forecast volumes at the midpoint, and for 2016 representing approximately 30% of oil, 50% of natural gas and 50% of NGL, assuming 2015 exit rate production. A summary of commodity derivative contracts through 2016 are as follows:

 
Derivative Position through 2016
as of October 21, 2015*
    Oil     Gas     NGL***
Period    

Volume
(MBbls)

Weighted Avg.
Price**
($/Bbl)

   

Volume
(BBTU)

Weighted Avg.
Price**
($/MMBTU)

   

Volume
(MBbls)

Weighted Avg.
Price - Mont
Belvieu
($/Bbl)

4Q15 2,006 $87.92 17,656 $4.07 1,709 $21.58
1Q16 1,868 $86.93 23,341 $3.90 2,250 $15.67
2Q16 1,752 $86.73 20,780 $3.39 2,018 $15.71
3Q16 1,170 $90.29 18,829 $3.33 1,613 $14.22
4Q16 780 $90.05 17,236 $3.83 1,280 $13.32
 
* Includes all commodity derivative contracts for settlement at any time during the fourth quarter of 2015 and later periods, entered into as of 10/21/15.
** Weighted average prices are shown as NYMEX equivalents. For collars, floor prices were used to calculate the weighted average price.
***NGL derivative positions include: 4Q15-2Q16 propane, ethane and butanes only; 3Q16-4Q16 propane and ethane only.
 

EARNINGS CALL INFORMATION

The Company has scheduled a webcast and conference call to discuss third quarter 2015 financial and operational results. The webcast is scheduled for October 28, 2015, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The webcast can be accessed from the Company's website at www.sm-energy.com, and will remain available for replay for approximately 30 days. You may also join via teleconference at the dial-in information below. A telephonic replay of the call will be available approximately two hours after the call through November 11, 2015.

       
Call Type     Phone Number     Conference ID
Domestic Participant     877-303-1292     57682556
Domestic Replay     855-859-2056     57682556
International Participant     315-625-3086     57682556
International Replay     404-537-3406     57682556
 

INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will” 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 factors such as the availability, proximity and capacity of gathering, processing and transportation facilities; the volatility and level of oil, natural gas, and natural gas liquids prices, including any impact on the Company’s asset carrying values or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results, including from pilot tests; the uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected divestiture, joint venture, farm down or similar efforts; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors” section of SM Energy's 2014 Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. The forward-looking statements contained herein speak as of the date of this announcement. 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 securities laws.

ABOUT THE COMPANY

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids in onshore North America. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at www.sm-energy.com.

 
SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS (unaudited)

September 30, 2015

           

Production Data

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,

2015 2014

Percent
Change

2015 2014

Percent
Change

 

Average realized sales price, before the effects of derivative settlements:

 
Oil (per Bbl) $ 40.03 $ 86.56 (54)% $ 43.43 $ 89.08 (51)%
Gas (per Mcf) 2.77 4.49 (38)% 2.69 4.86 (45)%
NGL (per Bbl) 15.18   34.86   (56)% 16.20   36.34   (55)%

Equivalent (per BOE)

$ 22.84 $ 47.06 (51)% $ 24.36 $ 48.63 (50)%

Average realized sales price, including the effects of derivative settlements:

 
Oil (per Bbl) $ 60.05 $

86.44

(31)% $ 61.67 $ 86.71 (29)%
Gas (per Mcf) 3.22 4.44 (27)% 3.38 4.60 (27)%
NGL (per Bbl) 16.12   35.47   (55)% 18.23   35.60   (49)%
Equivalent (per BOE) $ 29.92 $ 47.04 (36)% $ 32.22 $ 47.02 (31)%
 
Net production volumes:
Oil (MMBbl) 4.5 4.0 13% 14.8 11.6 28%
Gas (Bcf) 43.3 35.6 22% 133.5 109.1 22%
NGL (MMBbl) 4.3   3.2   35% 12.2   9.2   32%
MMBOE 16.1 13.1 22% 49.3 39.0 27%
 
Average net daily production:
Oil (MBbl per day) 49.1 43.5 13% 54.3 42.3 28%
Gas (MMcf per day) 471.1 386.5 22% 488.9 399.5 22%
NGL (MBbl per day) 46.8   34.6   35% 44.8   33.8   32%
MBOE (per day) 174.5 142.5 22% 180.6 142.7 27%
 
Per BOE Data:

Realized price, before the effects of derivative settlements

$ 22.84 $ 47.06 (51)% $ 24.36 $ 48.63 (50)%
Lease operating expense 3.86 4.58 (16)% 3.70 4.27 (13)%
Transportation costs 6.27 6.22 1% 5.99 6.25 (4)%
Production taxes 0.96 2.32 (59)% 1.16 2.30 (50)%
Ad valorem tax expense 0.40 0.49 (18)% 0.39 0.51 (24)%
General and administrative 2.35   3.18   (26)% 2.52   2.95   (15)%
Operating profit, before the effects of derivative settlements $ 9.00 $ 30.27 (70)% $ 10.60 $ 32.35 (67)%
Derivative settlement gain (loss) 7.08   (0.02 ) 35,500% 7.86   (1.61 ) 588%
Operating profit, including the effects of derivative settlements $ 16.08   $ 30.25   (47)% $ 18.46   $ 30.74   (40)%

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

$ 15.19 $ 13.97 9% $ 13.81 $ 14.07 (2)%
 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)

September 30, 2015

       

Condensed Consolidated Statements of Operations

(in thousands, except per share amounts)

For the Three Months
Ended September 30,

For the Nine Months
Ended September 30,

2015 2014 2015 2014
Operating revenues:
Oil, gas, and NGL production revenue $ 366,615 $ 617,207 $ 1,201,186 $ 1,894,977
Net gain (loss) on divestiture activity 2,415 (5,432 ) 38,497 52
Other operating revenues 2,121   7,011   13,548   31,457  

Total operating revenues and other income

371,151   618,786   1,253,231   1,926,486  
 
Operating expenses:
Oil, gas, and NGL production expense 184,568 178,390 554,404 519,697
Depletion, depreciation, amortization, and asset retirement obligation liability accretion 243,879 183,259 680,984 548,255
Exploration 19,679 34,556 82,627 80,161
Impairment of proved properties 55,990 124,430
Abandonment and impairment of unproved properties 6,600 15,522 24,046 18,487
General and administrative 37,782 41,696 124,026 114,862
Change in Net Profits Plan liability (4,364 ) (6,399 ) (13,174 ) (15,280 )
Derivative (gain) loss (212,253 ) (190,661 ) (285,491 ) 33,470
Other operating expenses 7,166   5,444   34,589   19,505  
Total operating expenses 339,047   261,807   1,326,441   1,319,157  
 
Income (loss) from operations 32,104 356,979 (73,210 ) 607,329
 
Non-operating income (expense):
Other, net 27 (672 ) 623 (2,493 )
Interest expense (33,157 ) (22,621 ) (96,583 ) (70,851 )
Loss on extinguishment of debt     (16,578 )  
 
Income (loss) before income taxes (1,026 ) 333,686 (185,748 ) 533,985
Income tax (expense) benefit 4,140   (124,748 ) 78,296   (199,660 )
 

Net income (loss)

$ 3,114   $ 208,938   $ (107,452 ) $ 334,325  
 
Basic weighted-average common shares outstanding 67,961   67,379   67,638   67,169  
 
Diluted weighted-average common shares outstanding 68,119   68,430   67,638   68,258  
 

Basic net income (loss) per common share

$ 0.05   $ 3.10   $ (1.59 ) $ 4.98  
 

Diluted net income (loss) per common share

$ 0.05   $ 3.05   $ (1.59 ) $ 4.90  
 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
   

Condensed Consolidated Balance Sheets

(in thousands, except share amounts)

September 30,
2015

December 31,
2014

ASSETS

Current assets:
Cash and cash equivalents $ 197 $ 120
Accounts receivable 171,067 322,630
Derivative asset 347,299 402,668
Prepaid expenses and other 19,114   19,625  
Total current assets 537,677   745,043  
 
Property and equipment (successful efforts method):
Proved oil and gas properties 7,468,331 7,348,436
Less - accumulated depletion, depreciation, and amortization (3,240,109 ) (3,233,012 )
Unproved oil and gas properties 381,869 532,498
Wells in progress 452,436 503,734

Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $74,894 and $22,482, respectively

29,173 17,891
Other property and equipment, net of accumulated depreciation of $43,197 and $37,079, respectively 359,339   334,356  
Total property and equipment, net 5,451,039   5,503,903  
 
Noncurrent assets:
Derivative asset 147,530 189,540
Other noncurrent assets 77,615   78,214  
Total other noncurrent assets 225,145   267,754  

Total Assets

$ 6,213,861   $ 6,516,700  
 

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued expenses $ 361,734 $ 640,684
Derivative liability 2,900
Deferred tax liability 120,563 142,976
Other current liabilities   1,000  
Total current liabilities 485,197   784,660  
 
Noncurrent liabilities:
Revolving credit facility 184,000 166,000
Senior Notes 2,350,000 2,200,000
Asset retirement obligation 118,153 120,867
Net Profits Plan liability 13,962 27,136
Deferred income taxes 833,352 891,681
Derivative liability 2,019 70
Other noncurrent liabilities 40,341   39,631  
Total noncurrent liabilities 3,541,827   3,445,385  
 
Stockholders’ equity:

Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 67,968,714 and 67,463,060, respectively

680

675
Additional paid-in capital 298,438 283,295
Retained earnings 1,899,803 2,013,997
Accumulated other comprehensive loss (12,084 ) (11,312 )
Total stockholders’ equity 2,186,837   2,286,655  

Total Liabilities and Stockholders’ Equity

$ 6,213,861   $ 6,516,700  
 
 
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
       

Condensed Consolidated Statements of Cash Flows

(in thousands)

For the Three Months
Ended September 30,

For the Nine Months
Ended September 30,

2015 2014 2015 2014
Cash flows from operating activities:
Net income (loss) $ 3,114 $ 208,938 $ (107,452 ) $ 334,325

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Net (gain) loss on divestiture activity (2,415 ) 5,432 (38,497 ) (52 )

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

243,879 183,259 680,984 548,255
Exploratory dry hole expense (36 ) 16,385 22,860 22,844
Impairment of proved properties 55,990 124,430
Abandonment and impairment of unproved properties 6,600 15,522 24,046 18,487
Stock-based compensation expense 7,277 10,227 20,492 24,568
Change in Net Profits Plan liability (4,364 ) (6,399 ) (13,174 ) (15,280 )
Derivative (gain) loss (212,253 ) (190,661 ) (285,491 ) 33,470
Derivative cash settlements 105,688 (274 ) 397,307 (62,894 )
Amortization of deferred financing costs 1,911 1,479 5,803 4,433
Non-cash loss on extinguishment of debt 4,123
Deferred income taxes 4,168 124,269 (80,388 ) 198,180
Plugging and abandonment (2,154 ) (2,974 ) (5,540 ) (6,193 )
Other, net 4,104 1,893 3,670 (2,934 )
Changes in current assets and liabilities:
Accounts receivable 66,385 9,034 105,336 6,476
Prepaid expenses and other (2,346 ) (1,068 ) 587 234
Accounts payable and accrued expenses (40,207 ) (15,093 ) (74,247 ) (28,797 )
Net cash provided by operating activities 235,341   359,969   784,849   1,075,122  
 
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties 115 (4,953 ) 335,103 41,868
Capital expenditures (287,741 ) (539,282 ) (1,261,871 ) (1,317,862 )
Acquisition of proved and unproved oil and gas properties (500 ) (360,658 ) (7,088 ) (459,277 )
Other, net 6   1,543   (990 ) (714 )
Net cash used in investing activities (288,120 ) (903,350 ) (934,846 ) (1,735,985 )
 
Cash flows from financing activities:
Proceeds from credit facility 374,000 536,500 1,604,500 536,500
Repayment of credit facility (312,000 ) (146,500 ) (1,586,500 ) (146,500 )
Net proceeds from Senior Notes (606 ) 490,951
Repayment of Senior Notes (350,000 )
Proceeds from sale of common stock 408 3,157 2,898
Dividends paid (3,373 ) (3,353 )
Net share settlement from issuance of stock awards (8,502 ) (10,576 ) (8,502 ) (10,576 )
Other, net 2   24   (159 ) (85 )

Net cash provided by financing activities

52,894   379,856   150,074   378,884  
 
Net change in cash and cash equivalents 115 (163,525 ) 77 (281,979 )
Cash and cash equivalents at beginning of period 82     163,794   120   282,248  
Cash and cash equivalents at end of period $ 197   $ 269   $ 197   $ 269  
 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015
       

Adjusted Net Income (Loss)

(in thousands, except per share data)
 

Reconciliation of net income (loss) (GAAP)

to adjusted net income (loss) (Non-GAAP):

For the Three Months
Ended September 30,

For the Nine Months
Ended September 30,

2015 2014 2015 2014
 
Reported net income (loss) (GAAP) $ 3,114 $ 208,938 $ (107,452 ) $ 334,325
 
Adjustments net of tax: (1)
Change in Net Profits Plan liability (2,758 ) (4,019 ) (8,326 ) (9,596 )
Derivative (gain) loss (134,144 ) (119,735 ) (180,430 ) 21,019
Derivative settlement gain (loss) (2) 71,855 (172 ) 245,038 (39,497 )
Net (gain) loss on divestiture activity (1,526 ) 3,411 (24,330 ) (33 )
Impairment of proved properties 35,386 78,640
Abandonment and impairment of unproved properties 4,171 9,748 15,197 11,610
Loss on extinguishment of debt 10,477
Unwinding of derivatives contracts related to Mid-continent (9,688 )
Other, net (3) 623 467 5,397 (5,092 )
       
Adjusted net income (loss) (Non-GAAP) (4) $ (23,279 ) $ 98,638   $ 24,523   $ 312,736  
 
Diluted weighted-average common shares outstanding: (5) 67,961   68,430   68,018   68,258  
 
Adjusted net income (loss) per diluted common share: $ (0.34 ) $ 1.44   $ 0.36   $ 4.58  
 

(1) Adjustments are shown net of tax and are calculated using a tax rate of 36.8% for the three and nine months ended September 30, 2015, and 37.2% for the three and nine months ended September 30, 2014, which approximates the Company's statutory tax rate for the respective periods, as adjusted for ordinary permanent differences.

 

(2) Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.

 

(3) For the three and nine-month periods ended September 30, 2015, the adjustment is related to the impairment of materials inventory and an estimated adjustment relating to claims on royalties on certain Federal and Indian leases, which are included in other operating expenses on the Company's condensed consolidated statements of operations. For the three and nine-month periods ended September 30, 2014, adjustments include items related to settlements from the previously disclosed litigation against Endeavour Operating Corporation. These items are included as a portion of other operating revenues and non-operating expense, other, net, on the Company's condensed consolidated statements of operations.

 

(4) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and generally 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, derivative (gain) loss net of derivative settlements, impairment of properties, and (gain) loss on divestiture activity. 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 (loss), income (loss) 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.

 

(5) For periods where the Company reports a GAAP net loss, the diluted weighted average share count is calculated using potentially dilutive securities related to unvested Restricted Stock Units and contingent Performance Share Units. On a GAAP basis, these items are not treated as dilutive securities in periods where the Company reports a GAAP loss for the period. Additionally, in periods where an adjusted net loss is calculated, all potentially dilutive shares are anti-dilutive and excluded from the calculation of adjusted net loss per diluted common share.

 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
September 30, 2015

Adjusted EBITDAX (3)

       
(in thousands)
 

Reconciliation of net income (loss) (GAAP) to adjusted EBITDAX (Non-GAAP) to net cash provided by operating activities (GAAP)

For the Three Months
Ended September 30,

 

For the Nine Months
Ended September 30,

 

2015 2014   2015 2014
Net income (loss) (GAAP) $ 3,114 $ 208,938 $ (107,452 ) $ 334,325
Interest expense 33,157 22,621 96,583 70,851
Other non-operating (income) expense, net (27 ) 672 (623 ) 2,493
Income tax expense (benefit) (4,140 ) 124,748 (78,296 ) 199,660

Depreciation, depletion, amortization, and asset retirement obligation liability accretion

243,879 183,259 680,984 548,255
Exploration (1)

17,798

32,155 77,298 74,696
Impairment of proved properties 55,990 124,430
Abandonment and impairment of unproved properties 6,600 15,522 24,046 18,487
Stock-based compensation expense 7,277 10,227 20,492 24,568
Derivative (gain) loss (212,253 ) (190,661 ) (285,491 ) 33,470
Derivative settlement gain (loss) (2) 113,695 (274 ) 387,719 (62,894 )
Change in Net Profits Plan liability (4,364 ) (6,399 ) (13,174 ) (15,280 )
Net (gain) loss on divestiture activity (2,415 ) 5,432 (38,497 ) (52 )
Loss on extinguishment of debt 16,578
Other, net 1,045     3,901    

Adjusted EBITDAX (Non-GAAP)

259,356   406,240   908,498   1,228,579  
Interest expense (33,157 ) (22,621 ) (96,583 ) (70,851 )
Other non-operating income (expense), net 27 (672 ) 623 (2,493 )
Income tax (expense) benefit 4,140 (124,748 ) 78,296 (199,660 )
Exploration (1) (17,798 ) (32,155 ) (77,298 ) (74,696 )
Exploratory dry hole expense (36 ) 16,385 22,860 22,844

Amortization of deferred financing costs

1,911 1,479 5,803 4,433
Deferred income taxes 4,168 124,269 (80,388 ) 198,180
Plugging and abandonment (2,154 ) (2,974 ) (5,540 ) (6,193 )
Loss on extinguishment of debt (12,455 )
Other, net 3,059 1,893 (231 ) (2,934 )
Changes in current assets and liabilities 15,825   (7,127 ) 41,264   (22,087 )
Net cash provided by operating activities (GAAP) $ 235,341   $ 359,969   $ 784,849   $ 1,075,122  
 
(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying condensed consolidated statements of operations because of the component of stock-based compensation expense recorded to exploration.
 
(2) Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities.
 
(3) Adjusted EBITDAX represents income (loss) before interest expense, other non-operating income or expense, income taxes, depreciation, depletion, amortization, and accretion expense, exploration expense, property impairments, non-cash stock based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors and analysts, as a performance measure, for analysis of the Company's ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to a financial covenant under its credit facility based on its debt to adjusted EBITDAX ratio. In addition, adjusted EBITDAX 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 EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
 

Source: SM Energy

SM Energy:
INVESTORS:
Jennifer Martin Samuels, 303-864-2507
jsamuels@sm-energy.com
or
MEDIA:
Patty Errico, 303-830-5052
perrico@sm-energy.com