SM Energy Reports Third Quarter Of 2016 Results - Executing On Our Long-Term Strategy And Delivering Strong Performance

SM Energy Company (NYSE: SM) today announced financial results for the third quarter of 2016 and provided an operations update. In conjunction with this release, the Company posted an investor presentation on its website at www.sm-energy.com with additional third quarter results and operations detail. This presentation will be referenced during the earnings webcast and conference call scheduled for 8:00 a.m. Mountain Time (10:00 Eastern Time) on November 2, 2016. Further information on the earnings webcast and conference call can be found below.

MANAGEMENT COMMENTARY

President and Chief Executive Officer Jay Ottoson comments:

"SM Energy has a straightforward strategy to generate differential shareholder returns by becoming a premier operator of top tier assets. Over the last few months, we have executed a series of transactions that will transform our portfolio and position our Company to operate an expansive inventory of highly economic, high margin drilling projects. Following completion of both our Rock Oil and QStar acquisitions in the Midland Basin, totaling $2.6 billion, and several non-core property divestitures totaling $980 million in gross proceeds, we will be focused on oil production from our pro forma 83,750 net acre position in the Midland Basin and natural gas/NGL production from our operated 161,475 net acre position in the Eagle Ford.

"Our confidence in our ability to realize exceptional value from these newly acquired properties is based on our outstanding operational competence. Our third quarter results again demonstrate excellent execution in operations with production higher and costs lower than expectations. Our operations team is quickly integrating activities on our acreage acquired from Rock Oil, actively incorporating learnings from completion improvement and down-spacing tests, and continuing to trade and bolt-on acreage across our positions to enable the drilling of longer lateral wells. We are executing our due diligence on QStar and closely monitoring field operations where early rates on a recent 9,700' well look terrific. We are keenly focused on bringing value forward in the Permian Basin, and our continued improvements in well performance and the potential to increase long lateral inventory are key drivers of value creation."

THIRD QUARTER 2016 RESULTS

Third quarter production of 14.2 MMBoe, or 153,880 Boe per day, was 31% oil, 25% NGLs and 44% natural gas. Production was down 12% compared with the third quarter of 2015, primarily due to decreased activity in the Eagle Ford, and down approximately 1% compared with the second quarter of 2016, as expected declines in Eagle Ford natural gas production as well as an early closing on the New Mexico divestiture were largely offset by increased oil production from the Permian and Williston Basins. For the first nine months of 2016, total production was 41.9 MMBoe and averaged 152,869 Boe per day.
               

PRODUCTION - SEQUENTIAL COMPARISON

3Q16

2Q16
 
Oil (MMBbls) 4.3 4.1
Natural gas (Bcf) 37.1 39.0
NGLs (MMBbls) 3.6 3.7
 
Equivalent (MMBoe) 14.2 14.3
 

Realized prices in the third quarter of 2016 averaged $23.25 per Boe (before the effect of commodity derivatives). The average realized price was up 2% compared with the third quarter of 2015, primarily due to a higher oil component in the commodity mix and improved NGL prices, and up 14% compared with the second quarter of 2016, predominantly due to a 44% increase in benchmark natural gas prices. For the first nine months of 2016, the average realized price was $19.87 per Boe. Derivative settlements added $4.06 per Boe in the third quarter of 2016 and added $7.31 per Boe in the first nine months of 2016.
   

REALIZED PRICES - SEQUENTIAL COMPARISON
           

3Q16

2Q16

Pre/Post-Hedge

Pre/Post-Hedge
 
Oil ($/Bbl) 38.81/50.15 39.38/56.97
Natural gas ($/Mcf) 2.71/ 2.98 1.79/ 2.60
NGLs ($/Bbl) 16.58/16.07 16.12/15.61
 
Equivalent ($/Boe) 23.25/27.31 20.35/27.45
 

Third quarter 2016 lease operating expense (including ad valorem tax) of $3.50 per Boe was down 18% compared with the third quarter of 2015 and flat compared with the second quarter of 2016. Operating expense continues to benefit from lower vendor rates and relentless focus by the operations team on gaining efficiencies in all of the Company's production operations. Total Company transportation expense for the third quarter of 2016 of $6.24 per Boe was nearly flat with the same prior year period and up 5% sequentially. For the first nine months of 2016, lease operating expense (including ad valorem) was $3.68 per Boe compared with $4.09 per Boe in the first nine months of 2015. For the first nine months of 2016, transportation expense averaged $6.08 per Boe compared with $5.99 in the first nine months of 2015. See below for revisions to guidance as a result of lower operating costs.

Third quarter 2016 general and administrative expense of $32.7 million was down 14% compared with the third quarter of 2015 and was up 16% sequentially. In the third quarter of 2016, general and administrative expense included $2.9 million related to closure of the Company's Billings, Montana office, as well as $5.0 million of non-cash stock-based compensation charges. In the prior year period, general and administrative expense included $1.0 million related to office closure and other reorganization charges, as well as $5.4 million in non-cash stock-based compensation. General and administrative expense is lower year-over-year primarily because the Company has consolidated regional offices and reduced headcount. For the first nine months of 2016, general and administrative expense was $93.1 million (including $15.4 million of non-cash stock-based compensation) and included $2.9 million of office closure and reorganization charges compared with the first nine months of 2015 at $124.0 million (including $15.2 million of non-cash stock-based compensation), which included $9.5 million of office closure and reorganization expenses. The Company expects to incur an additional $3.0 million of office closure and reorganization charges in the fourth quarter of 2016.

The Company's GAAP net loss for the third quarter of 2016 was $40.9 million, or $0.52 per diluted common share, compared with net income of $3.1 million, or $0.05 per diluted common share, in the third quarter of 2015. The year-over-year decline in net income was primarily due to significantly higher cash and non-cash derivative gains in the 2015 period, partially offset by lower impairment expense, higher gain on divestiture activity and lower depletion, depreciation and amortization expenses, each in the 2016 period. In addition, interest expense in the third quarter of 2016 includes a one-time cash charge of $10 million for a committed second lien facility, in conjunction with the announcement of the acquisition of assets from Rock Oil Holdings LLC, that the Company did not utilize and ultimately terminated during the quarter. Net loss for the first nine months of 2016 was $556.8 million, or $7.78 per diluted common share (including $427.3 million in non-cash derivative losses and $285.4 million in impairment charges), compared with a net loss of $107.5 million (including $102.2 million in non-cash derivative losses and $148.5 million in impairment charges), or $1.59 per diluted common share, for the first nine months of 2015.

Adjusted EBITDAX, adjusted net income and adjusted net income per diluted share are non-GAAP measures. Please reference the reconciliations to the most directly comparable GAAP financial measures at the end of this release.

The Company's adjusted EBITDAX for the third quarter of 2016 was $205.1 million, compared with $259.4 million in the prior year period. The year-over-year decline in adjusted EBITDAX was predominantly due to higher cash derivative settlement gains in the 2015 period. Compared sequentially with the second quarter of 2016, adjusted EBITDAX was down $12.0 million, with the second quarter benefiting from a slightly higher margin per Boe, which included the benefit from hedge gains. Adjusted EBITDAX for the first nine months of 2016 was $604.6 million, compared with $908.5 million in the prior year period.

The Company's adjusted net loss for the third quarter of 2016 was $29.0 million, or $0.37 per diluted common share, compared with adjusted net loss of $23.3 million, or $0.34 per diluted common share, in the third quarter of 2015. For the first nine months of 2016, the Company's adjusted net loss was $115.8 million, or $1.62 per diluted common share, compared with adjusted net income of $24.5 million, or $0.36 per diluted common share, for the first nine months of 2015. The calculation of adjusted net loss excludes non-recurring items and items difficult to estimate in order to present results that can be more consistently compared with prior periods and peer results.

FINANCIAL POSITION AND LIQUIDITY

At September 30, 2016, the outstanding principal balance on the Company's long-term debt included $2.8 billion in senior notes plus $172.5 million in senior convertible notes. The Company's senior secured credit facility was undrawn. Also at quarter-end, the Company had a cash balance of $980.7 million, which the Company applied to closing the Rock Oil acquisition on October 4, 2016.

As previously announced, during the quarter, the Company:

  • issued $500 million 6.750% senior unsecured notes due 2026;
  • issued $172.5 million 1.500% senior unsecured convertible notes due 2021;
  • issued 18.4 million shares of common stock for gross proceeds of $552 million; and
  • closed $195 million in asset divestitures, subject to pre- and post-closing adjustments.

Also as previously announced, subsequent to quarter-end, the Company:
  • closed on the acquisition of Midland Basin assets from Rock Oil Holdings LLC for $991 million, subject to post-closing adjustments;
  • announced a definitive agreement to acquire Midland Basin assets from QStar LLC and a related entity for $1.6 billion; under these agreements the sellers will be issued approximately 13.4 million shares of SM Energy common stock to fund $500 million of the purchase price;
  • announced a definitive agreement to sell the Company's properties in the Williston Basin located outside of Divide County, North Dakota to Oasis Petroleum for $785 million, subject to pre- and post-closing adjustments; and
  • continued the marketing process for its interests in third party-operated Eagle Ford assets, including its ownership in associated midstream assets.

Closings of the QStar acquisition in the Midland Basin and closing of the Williston Basin divestiture are both anticipated in December 2016. The closings of these transactions are subject to the satisfaction of customary closing conditions, and there can be no assurance that either of these transactions will close on-time or at all.

Currently, the Company's senior secured revolving credit facility has a borrowing base of $1.35 billion and lender commitments of $1.25 billion.

CAPITAL ACTIVITY AND OPERATIONS

Costs incurred in oil and gas activities for the third quarter of 2016 were $156.4 million and for the first nine months of 2016 were $561.2 million. Total capital spend (before acquisitions) for the third quarter of 2016 was $145.4 million and for the first nine months of 2016 was $518.3 million. Please refer to the Total Capital Spend Reconciliation at the end of this release for a reconciliation of the Company's Costs incurred in oil and gas activities (GAAP) to Total capital spend (Non-GAAP).Total capital spend (before acquisitions) guidance for 2016 is approximately $700 million, which includes the expected addition of two rigs in the Midland Basin during the fourth quarter. The Company is unable to present a quantitative reconciliation of this forward-looking non-GAAP financial measure without unreasonable effort because acquisition costs are inherently unpredictable. Acquisition costs could be significant in future periods and would depend on a wide variety of factors outside the Company's control. Accordingly, investors are cautioned not to place undue reliance on this information.

During the third quarter, the Company drilled 16 gross/16 net operated wells and completed 63 gross/61 net operated wells. The Company's drilled and uncompleted (DUC) inventory at September 30, 2016 was 82 gross/79 net operated wells plus 27 net non-operated wells.

PERMIAN BASIN

Third quarter of 2016 Permian Basin net production was 986,000 Boe (10,700 Boe/d) and was 74% oil. Production increased 16% sequentially with activity that included drilling seven net wells and completing nine net wells.

Subsequent to quarter-end, the Company completed the acquisition of more than 26,000 net acres (adjusted for acres acquired after the transaction was announced) in Howard County, Texas, for $991 million (subject to post- closing adjustments) and announced the signing of definitive agreements to acquire an additional 35,700 net acres in Howard and Martin Counties for $1.6 billion. The second set of transactions is expected to close in December and is expected to result in expanding the Company's total Midland Basin position from 21,975 net acres at the end of the second quarter to approximately 83,750 net acres by year-end. The Company added a third rig to its Permian program with the close of the first acquisition and anticipates running four rigs by year-end.

Company-wide, the Company is gearing up for increased activity in the Permian Basin. The integration of the Rock Oil assets is going smoothly and the Company is actively relocating employees to develop and operate these assets. The Company also has its employees monitoring operations on the QStar assets where drilling recently commenced on a 3-well pad. Further, QStar recently completed a 9,700' lateral well with an average 14-day production rate of approximately 1,830 Boe/d. At Sweetie Peck, the Company is conducting down-spacing tests to approximately 400' in the Wolfcamp B and Lower Spraberry. Across the basin, the Company continues to bolt-on adjacent acreage positions, including approximately 1,300 net acres adjacent to the original Rock Oil position since the announcement of the acquisition, as well as negotiate trades with neighboring operators to maximize the potential for drilling 10,000' laterals.

Going forward, the Company plans to primarily focus its capital program on Permian Basin activity where high oil content, high operating margins and continued top tier operational performance have the potential to drive substantial growth in cash flows.

EAGLE FORD

Third quarter of 2016 Eagle Ford net production was 10.4 MMBoe (113,400 Boe/d), of which 8.0 MMBoe was operated and 2.5 MMBoe was third party operated. Consistent with the Company's forecast, production declined approximately 4.9% sequentially related to declining natural gas volumes. During the quarter, the Company drilled three wells and completed 25 wells in the area. New completions were located in higher oil/lower natural gas areas. The Company expects to restart drilling activity in its operated Eagle Ford program in the first quarter of 2017 and expects to continue completing DUCs during the fourth quarter of 2016. The Company continues to employ co-development of the Lower and Upper Eagle Ford formations along with drilling longer laterals and enhanced completion designs.

The Company is in the process of marketing its third party operated Eagle Ford assets, including its ownership interest in related mid-stream assets, and anticipates completing the sale in the first quarter of 2017.

ROCKY MOUNTAIN

Third quarter of 2016 Rocky Mountain net production was 2.7 MMBoe (29,800 Boe/d) and was 81% oil. The Rocky Mountain region includes the Company's Williston Basin and Powder River Basin assets. Regional production from only Divide County, North Dakota was approximately 0.9 MMBoe (9,350 Boe/d). During the quarter, the Company drilled five net wells and completed 26 net wells in Divide County, North Dakota. The majority of newly completed wells experienced delayed initial production resulting from downtime while the Company installed pumping units. The Company is currently operating one rig in the Williston Basin.

During the quarter, the Company completed the sale of certain non-core assets in the Rocky Mountain region and, subsequent to quarter-end, announced a definitive agreement for the sale of its Raven/Bear Den and other Williston Basin assets outside of Divide County, North Dakota. This sale is expected to close in early December 2016.

GUIDANCE

Full year 2016 guidance is revised as follows:
     
    Total capital spend (before acquisitions) ($MM) $700
Total production (MMBoe) 55.3-56.0
LOE including ad valorem ($/Boe) $3.60-3.65
Transportation ($/Boe) $6.05-6.15
Production taxes ~$1.00 or 5%
G&A (including approximately $21-23MM non-cash,
stock-based compensation expense) ($MM) $128-130
Exploration before dry hole expenses ($MM) $60-64
(this amount is a component of capital guidance)
DD&A ($/Boe) $14.50-14.80
 

Fourth quarter of 2016 production is expected to range between 13.3 and 14.0 MMBoe. Fourth quarter production volumes and commodity mix will be affected by timing of the close date on the sale of Williston assets, which include Raven/Bear Den and associated production.

Total capital spend (before acquisitions) is a non-GAAP measure. The Company is unable to present a quantitative reconciliation of this forward-looking non-GAAP financial measure without unreasonable effort because acquisition costs are inherently unpredictable. Acquisition costs could be significant in future periods and would depend on a wide variety of factors outside the Company's control. Accordingly, investors are cautioned not to place undue reliance on this information.

COMMODITY DERIVATIVES

As of October 26, 2016

For the fourth quarter of 2016, the Company has commodity derivatives in place for approximately 70% of expected oil production, 75% of expected natural gas production and 55% of expected NGL production.
                           
OIL SWAPS OIL COLLARS NATURAL GAS SWAPS NGL SWAPS
Volume/Average Price Volume/Avg. Ceiling - Floor Volume/Average Price Volume/Average Price
Period (MBbls/$Bbl) (MBbls/$Bbl) (BBtu/$MMBtu) (MBbls/$Bbl)
 
4Q16 2,249/$59.03 881/$51.52 - $40.00 26,700/$3.34 1,888/$15.94
 
1Q17 1,574/$46.41 704/$54.17 - $45.00 28,222/$3.78 1,911/$19.12
 
2Q17 1,445/$46.44 636/$54.10 - $45.00 25,669/$4.00 1,762/$19.18
 
3Q17 1,340/$46.66 583/$54.05 - $45.00 23,657/$4.01 1,640/$19.26
 
4Q17 1,253/$46.35 540/$54.01 - $45.00 22,001/$3.98 1,539/$19.22
 

Notes: The volumes above represent fixed swap and collar contracts the Company has in place through 4Q17. Volumes for 4Q16 include all commodity contracts for settlement any time during the fourth quarter of 2016; prices are weighted averages; natural gas contracts reflect regional contract positions and are no longer adjusted to a NYMEX equivalent; NGL prices are at Mt. Belvieu and reflect specific NGL components, 4Q16 includes ethane, propane, and butanes, and 2017 quarters include ethane, propane, butanes and gasoline.

THIRD QUARTER 2016 WEBCAST AND CONFERENCE CALL

Please join SM Energy management at 8:00 a.m. Mountain time/10:00 a.m. Eastern time Wednesday, November 2, 2016, for a discussion of third quarter financial and operating results via webcast (available live and for replay) on the Company's website at www.sm-energy.com. Please reference the Third Quarter Earnings IR presentation available on the Company's website.

Alternatively, you may join by telephone with the passcode 5999858 (applicable for live and replay calls) at:

Live - Domestic toll free/International: 877-303-1292/315-625-3086

Replay - Domestic toll free/International: 855-859-2056/404-537-3406

The call replay will be available approximately two hours after the call until November 16, 2016.

FORWARD-LOOKING STATEMENTS

This release contains forward-looking statements within the meaning of securities laws. The words "anticipate," "assume," "believe," "budget," "estimate," "expect," "forecast," "guidance," "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. Forward-looking statements in this release include, among other things, guidance on forecast results and metrics, expectations regarding growth strategy, consummation of pending transactions, anticipated drilling plans and capital expenditures, anticipated growth in cash flows, the expected benefits, financing sources and timing of acquisitions, and the expected benefits and likelihood of completing divestitures. General risk factors include the uncertain nature of acquisition, 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 acquisition, divestiture, joint venture, farm down or similar efforts; the uncertainty of negotiations to result in an agreement or a completed transaction; the availability of and access to capital markets; 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 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 2015 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
September 30, 2016
                       

For the Three Months Ended September 30,

For the Nine Months Ended September 30,

Production Data
2016 2015

Percent Change
2016 2015

Percent Change
 
Average realized sales price, before the effects of
derivative settlements:
Oil (per Bbl) $ 38.81 $ 40.03 (3 )% $ 34.69 $ 43.43 (20 )%
Gas (per Mcf) 2.71 2.77 (2 )% 2.12 2.69 (21 )%
NGL (per Bbl) 16.58   15.18   9 % 14.91   16.20   (8 )%
Equivalent (per BOE) $ 23.25 $ 22.84 2 % $ 19.87 $ 24.36 (18 )%
 
Average realized sales price, including the effects of
derivative settlements:
Oil (per Bbl) $ 50.15 $ 60.05 (16 )% $ 52.31 $ 61.67 (15 )%
Gas (per Mcf) 2.98 3.22 (7 )% 2.86 3.38 (15 )%
NGL (per Bbl) 16.07   16.12   % 15.12   18.23   (17 )%
Equivalent (per BOE) $ 27.31 $ 29.92 (9 )% $ 27.18 $ 32.22 (16 )%
 
Production:
Oil (MMBbl) 4.3 4.5 (4 )% 12.6 14.8 (15 )%
Gas (Bcf) 37.1 43.3 (14 )% 111.7 133.5 (16 )%
NGL (MMBbl) 3.6   4.3   (16 )% 10.7   12.2   (13 )%
MMBOE (6:1) 14.2 16.1 (12 )% 41.9 49.3 (15 )%
 
Average daily production:
Oil (MBbl/d) 47.2 49.1 (4 )% 45.9 54.3 (16 )%
Gas (MMcf/d) 403.0 471.1 (14 )% 407.8 488.9 (17 )%
NGL (MBbl/d) 39.5   46.8   (16 )% 39.0   44.8   (13 )%
MBOE/d (6:1) 153.9 174.5 (12 )% 152.9 180.6 (15 )%
 
Per BOE Data:
Realized price, before the effects of derivative settlements $ 23.25 $ 22.84 2 % $ 19.87 $ 24.36 (18 )%
Lease operating expense 3.29 3.86 (15 )% 3.46 3.70 (6 )%
Transportation costs 6.24 6.27 % 6.08 5.99 2 %
Production taxes 1.04 0.96 8 % 0.88 1.16 (24 )%
Ad valorem tax expense 0.21 0.40 (48 )% 0.22 0.39 (44 )%
General and administrative (excluding stock-compensation) 1.96   2.02   (3 )% 1.85   2.21   (16 )%
Net, before the effects of derivative settlements $ 10.51 $ 9.33 13 % $ 7.38 $ 10.91 (32 )%
Derivative settlement gain 4.06   7.08   (43 )% 7.31   7.86   (7 )%
Margin, including the effects of derivative settlements $ 14.57   $ 16.41   (11 )% $ 14.69   $ 18.77   (22 )%
 

Depletion, depreciation, amortization, andasset retirement obligation liability accretion
$ 13.70 $ 15.19 (10 )% $ 14.78 $ 13.81 7 %
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2016
               

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,
2016 2015 2016 2015
Operating revenues:
Oil, gas, and NGL production revenue $ 329,165 $ 366,615 $ 832,130 $ 1,201,186
Net gain on divestiture activity 22,388 2,415 3,413 38,497
Other operating revenues 1,107   2,121   2,007   13,548  
Total operating revenues and other income 352,660   371,151   837,550   1,253,231  
 
Operating expenses:
Oil, gas, and NGL production expense 152,524 184,568 445,658 554,404

Depletion, depreciation, amortization, and asset retirementobligation liability accretion
193,966 243,879 619,193 680,984
Exploration (1) 13,482 19,679 41,942 82,627
Impairment of proved properties 8,049 55,990 277,834 124,430
Abandonment and impairment of unproved properties 3,568 6,600 5,917 24,046
General and administrative (including stock-based compensation) (1) 32,679 37,782 93,117 124,026
Change in Net Profits Plan liability (8,314 ) (4,364 ) (6,449 ) (13,174 )
Derivative (gain) loss (2) (28,037 ) (212,253 ) 121,086 (285,491 )
Other operating expenses 2,397   7,166   14,180   34,589  
Total operating expenses 370,314   339,047   1,612,478   1,326,441  
 
Income (loss) from operations (17,654 ) 32,104 (774,928 ) (73,210 )
 
Non-operating income (expense):
Interest expense (47,206 ) (33,157 ) (112,329 ) (96,583 )
Gain (loss) on extinguishment of debt 15,722 (16,578 )
Other, net 221   27   232   623  
 
Loss before income taxes (64,639 ) (1,026 ) (871,303 ) (185,748 )
Income tax benefit 23,732   4,140   314,505   78,296  
 
 
Net income (loss) $ (40,907 ) $ 3,114   $ (556,798 ) $ (107,452 )
 
Basic weighted-average common shares outstanding 78,468   67,961   71,574   67,638  
 
Diluted weighted-average common shares outstanding 78,468   68,119   71,574   67,638  
 
Basic net income (loss) per common share $ (0.52 ) $ 0.05   $ (7.78 ) $ (1.59 )
 
Diluted net income (loss) per common share $ (0.52 ) $ 0.05   $ (7.78 ) $ (1.59 )
 
 

(1) Non-cash stock-based compensation component included in:

Exploration expense
$ 1,590 $ 1,881 $ 5,037 $ 5,329

G&A expense
$ 4,980 $ 5,395 $ 15,448 $ 15,163
 

(2) The Derivative (gain) loss line item consists of the following:

Settlement gain
$ (57,496 ) $ (113,695 ) $ (306,234 ) $ (387,719 )

(Gain) loss on fair value changes
$ 29,459   $ (98,558 ) $ 427,320   $ 102,228  

Total derivative (gain) loss:
$ (28,037 ) $ (212,253 ) $ 121,086   $ (285,491 )
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2016
       

Condensed Consolidated Balance Sheets
(in thousands, except share amounts) September 30, December 31,
ASSETS 2016 2015
 
Current assets:
Cash and cash equivalents $ 980,666 $ 18
Accounts receivable 140,799 134,124
Derivative asset 109,818 367,710
Prepaid expenses and other 15,326   17,137  
Total current assets 1,246,609   518,989  
 
Property and equipment (successful efforts method):
Proved oil and gas properties 5,406,656 7,606,405
Less - accumulated depletion, depreciation, and amortization (2,668,060 ) (3,481,836 )
Unproved oil and gas properties 177,787 284,538
Wells in progress 201,241 387,432
Oil and gas properties held for sale, net 1,109,517 641

Other property and equipment, net of accumulated depreciation of $41,958 and$32,956, respectively
137,553   153,100  
Total property and equipment, net 4,364,694   4,950,280  
 
Noncurrent assets:
Derivative asset 107,029 120,701
Restricted cash 49,000
Other noncurrent assets 18,101   31,673  
Total other noncurrent assets 174,130   152,374  
 
Total Assets $ 5,785,433   $ 5,621,643  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 277,571 $ 302,517
Derivative liability 51,059   8  
Total current liabilities 328,630   302,525  
 
Noncurrent liabilities:
Revolving credit facility 202,000

Senior Notes, net of unamortized deferred financing costs
2,765,398 2,315,970
Senior Convertible Notes, net of unamortized deferred financing costs 128,925
Asset retirement obligation 66,158 137,284
Asset retirement obligation associated with oil and gas properties held for sale 46,290 241
Net Profits Plan liability 1,162 7,611
Deferred income taxes 453,712 758,279
Derivative liability 104,705
Other noncurrent liabilities 42,538   45,332  
Total noncurrent liabilities 3,608,888   3,466,717  
 
Stockholders' equity:

Common stock, $0.01 par value - authorized: 200,000,000 shares; issued andoutstanding: 86,868,482 and 68,075,700, respectively
869 681
Additional paid-in capital 866,239 305,607
Retained earnings 994,969 1,559,515
Accumulated other comprehensive loss (14,162 ) (13,402 )
Total stockholders' equity 1,847,915   1,852,401  
 
Total Liabilities and Stockholders' Equity $ 5,785,433   $ 5,621,643  
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2016
               

Condensed Consolidated Statements of Cash Flows

(in thousands)

For the Three Months Ended September 30,

For the Nine Months Ended September 30,
2016 2015 2016 2015
Cash flows from operating activities:
Net income (loss) $ (40,907 ) $ 3,114 $ (556,798 ) $ (107,452 )

Adjustments to reconcile net income (loss) to net cash provided byoperating activities:
Net gain on divestiture activity (22,388 ) (2,415 ) (3,413 ) (38,497 )

Depletion, depreciation, amortization, and asset retirementobligation liability accretion
193,966 243,879 619,193 680,984
Exploratory dry hole expense 8 (36 ) (16 ) 22,860
Impairment of proved properties 8,049 55,990 277,834 124,430
Abandonment and impairment of unproved properties 3,568 6,600 5,917 24,046
Stock-based compensation expense 6,570 7,277 20,485 20,492
Change in Net Profits Plan liability (8,314 ) (4,364 ) (6,449 ) (13,174 )
Derivative (gain) loss (28,037 ) (212,253 ) 121,086 (285,491 )
Derivative settlement gain 57,496 113,695 306,234 387,719
Amortization of discount and deferred financing costs 3,757 1,911 5,687 5,803
Non-cash (gain) loss on extinguishment of debt, net (15,722 ) 4,123
Deferred income taxes (23,756 ) 4,168 (314,770 ) (80,388 )
Plugging and abandonment (2,506 ) (2,154 ) (5,222 ) (5,540 )
Other, net (3,068 ) 4,104 (2,392 ) 3,670
Changes in current assets and liabilities:
Accounts receivable 12,441 66,385 1,221 105,336
Prepaid expenses and other (835 ) (2,346 ) 7,652 587
Accounts payable and accrued expenses (3,439 ) (40,207 ) (65,166 ) (74,247 )
Accrued derivative settlements 5,534   (8,007 ) 19,651   9,588  
Net cash provided by operating activities 158,139   235,341   415,012   784,849  
 
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties 188,862 115 201,829 335,103
Capital expenditures (147,224 ) (287,741 ) (492,794 ) (1,261,871 )
Acquisition of proved and unproved oil and gas properties (4,102 ) (500 ) (21,853 ) (7,088 )
Acquisition deposit held in escrow (49,000 ) (49,000 )
Other, net 900   6     (990 )
Net cash used in investing activities (10,564 ) (288,120 ) (361,818 ) (934,846 )
 
Cash flows from financing activities:
Proceeds from credit facility 158,000 374,000 743,000 1,604,500
Repayment of credit facility (488,500 ) (312,000 ) (945,000 ) (1,586,500 )
Debt issuance costs related to credit facility (3,132 )
Net proceeds from Senior Notes 492,397 (606 ) 492,397 490,951
Cash paid to repurchase Senior Notes (29,904 ) (350,000 )
Net proceeds from Senior Convertible Notes 166,681 166,681
Cash paid for capped call transactions (24,109 ) (24,109 )
Net proceeds from sale of common stock 530,912 533,266 3,157
Dividends paid (3,404 ) (3,373 )
Net share settlement from issuance of stock awards (2,308 ) (8,502 ) (2,341 ) (8,502 )
Other, net   2     (159 )
Net cash provided by financing activities 833,073   52,894   927,454   150,074  
 
Net change in cash and cash equivalents 980,648 115 980,648 77
Cash and cash equivalents at beginning of period 18   82   18   120  
Cash and cash equivalents at end of period $ 980,666   $ 197   $ 980,666   $ 197  
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2016
 

Condensed Consolidated Statement of Stockholders' Equity
(in thousands, except share amounts)
     

Additional Paid-in Capital
       

Accumulated Other Comprehensive Loss
   

Total Stockholders' Equity
Common Stock

Retained Earnings
Shares     Amount
Balances, December 31, 2015 68,075,700 $ 681 $ 305,607 $ 1,559,515 $ (13,402 ) $ 1,852,401
Net loss (556,798 ) (556,798 )
Other comprehensive loss (760 ) (760 )
Cash dividends, $ 0.10 per share (7,748 ) (7,748 )
Issuance of common stock under Employee Stock Purchase Plan 140,853 1 2,353 2,354

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings
198,456 2 (2,343 ) (2,341 )
Stock-based compensation expense 53,473 1 20,484 20,485
Issuance of common stock from stock offering 18,400,000 184 530,728 530,912
Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of issuance costs 38,860 38,860
Purchase of capped call transactions (24,183 ) (24,183 )

Deferred tax liability related to integratedSenior Convertible Notes, net
    (5,267 )     (5,267 )
Balances, September 30, 2016 86,868,482   $ 869   $ 866,239   $ 994,969   $ (14,162 ) $ 1,847,915  
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2016
                 

Adjusted Net Income (Loss) (Non-GAAP)
(in thousands, except per share data)

For the Three Months Ended September 30,

For the Nine Months Ended September 30,
2016 2015 2016 2015
Net income (loss) (GAAP) $ (40,907 ) $ 3,114 $ (556,798 ) $ (107,452 )
Change in Net Profits Plan liability (8,314 ) (4,364 ) (6,449 ) (13,174 )
Derivative (gain) loss (28,037 ) (212,253 ) 121,086 (285,491 )
Derivative settlement gain 57,496 113,695 306,234 387,719
Net gain on divestiture activity (22,388 ) (2,415 ) (3,413 ) (38,497 )
Impairment of proved properties 8,049 55,990 277,834 124,430
Abandonment and impairment of unproved properties 3,568 6,600 5,917 24,046
(Gain) loss on extinguishment of debt (15,722 ) 16,578
Unwinding of derivative contracts related to Mid-continent (15,329 )
Termination fee on temporary second lien facility 10,000 10,000
Other, net (2) (1,694 ) 986 (976 ) 8,540
Tax effect of adjustments (1) (6,818 ) 15,368   (253,497 ) (76,847 )
Adjusted net income (loss) (Non-GAAP) (3) $ (29,045 ) $ (23,279 ) $ (115,784 ) $ 24,523  
 
Diluted net income (loss) per common share (GAAP) $ (0.52 ) $ 0.05 $ (7.78 ) $ (1.58 )
Change in Net Profits Plan liability (0.11 ) (0.06 ) (0.09 ) (0.19 )
Derivative (gain) loss (0.36 ) (3.12 ) 1.69 (4.20 )
Derivative settlement gain 0.73 1.67 4.28 5.70
Net gain on divestiture activity (0.29 ) (0.04 ) (0.05 ) (0.57 )
Impairment of proved properties 0.10 0.82 3.88 1.83
Abandonment and impairment of unproved properties 0.05 0.10 0.08 0.35
(Gain) loss on extinguishment of debt (0.22 ) 0.24
Unwinding of derivative contracts related to Mid-continent (0.22 )
Termination fee on temporary second lien facility 0.13 0.14
Other, net (2) (0.01 ) 0.01 (0.01 ) 0.13
Tax effect of adjustments (1) (0.09 ) 0.23   (3.54 ) (1.13 )
Adjusted net income (loss) per diluted common share (Non-GAAP) $ (0.37 ) $ (0.34 ) $ (1.62 ) $ 0.36  
 

Reconciliation of diluted weighted-average common shares (GAAP) to adjusted diluted weighted-average shares outstanding (Non-GAAP) (4):
 
Diluted weighted-average shares outstanding (GAAP) 78,468 68,119 71,574 67,638
Dilutive shares adjustment   (158 )   380  
Adjusted diluted weighted-average shares outstanding (Non-GAAP) 78,468   67,961   71,574   68,018  

 

(1) The tax effect of adjustments is calculated using a tax rate of 36.5% for the three and nine month periods ending September 30, 2016 and 36.8% for the three and nine month periods ended September 30, 2015. These rates approximate the Company's statutory tax rate for the respective periods, as adjusted for ordinary permanent differences.

(2) For the nine-month periods ended September 30, 2016 and 2015, and the three-month period ended September 30, 2015, the adjustments are related to impairment of materials inventory and adjustments relating to claims on royalties on certain Federal and Indian leases. For the three-month period ended September 30, 2016, the adjustment is related to claims on royalties on certain Federal and Indian leases. These items are included in other operating expenses on the Company's condensed consolidated statements of operations.

(3) Adjusted net income (loss) excludes certain items that the Company believes affect the comparability of operating results. Items excluded generally are non-recurring items or are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as the change in the Net Profits Plan liability, derivative (gain) loss, net of derivative settlement gains, impairments, and net (gain) loss on divestiture activity. The non-GAAP measure of adjusted net income (loss) 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 (loss) 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 (loss) 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 (loss) excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted net income (loss) amounts presented may not be comparable to similarly titled measures of other companies.

(4) For periods where the Company reports a GAAP net loss, the diluted weighted-average common shares outstanding equals the basic weighted average common shares outstanding. Potentially dilutive securities related to unvested Restricted Stock Units, contingent Performance Share Units, and shares into which the Senior Convertible Notes are convertible are not treated as dilutive securities in periods where the Company reports a GAAP net loss for the period. In periods where the Company reports adjusted net income, those dilutive securities are included in the adjusted diluted weighted-average common shares outstanding. In periods where the Company reports adjusted net loss, those dilutive securities are not included in the adjusted diluted weighted average common shares outstanding.
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
September 30, 2016
                 
Adjusted EBITDAX (1)
(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,
2016 2015 2016 2015
Net income (loss) (GAAP) $ (40,907 ) $ 3,114 $ (556,798 ) $ (107,452 )
Interest expense 47,206 33,157 112,329 96,583
Other non-operating income, net (221 ) (27 ) (232 ) (623 )
Income tax benefit (23,732 ) (4,140 ) (314,505 ) (78,296 )

Depletion, depreciation, amortization, and asset retirementobligation liability accretion
193,966 243,879 619,193 680,984
Exploration (2) 11,892 17,798 36,905 77,298
Impairment of proved properties 8,049 55,990 277,834 124,430
Abandonment and impairment of unproved properties 3,568 6,600 5,917 24,046
Stock-based compensation expense 6,570 7,277 20,485 20,492
Derivative (gain) loss (28,037 ) (212,253 ) 121,086 (285,491 )
Derivative settlement gain (3) 57,496 113,695 306,234 387,719
Change in Net Profits Plan liability (8,314 ) (4,364 ) (6,449 ) (13,174 )
Net gain on divestiture activity (22,388 ) (2,415 ) (3,413 ) (38,497 )
(Gain) loss on extinguishment of debt (15,722 ) 16,578
Materials inventory impairment   1,045   1,692   3,901  
Adjusted EBITDAX (Non-GAAP) (1) $ 205,148   $ 259,356   $ 604,556   $ 908,498  
Interest expense (47,206 ) (33,157 ) (112,329 ) (96,583 )
Other non-operating income, net 221 27 232 623
Income tax benefit 23,732 4,140 314,505 78,296
Exploration (2) (11,892 ) (17,798 ) (36,905 ) (77,298 )
Exploratory dry hole expense 8 (36 ) (16 ) 22,860
Amortization of discount and deferred financing costs 3,757 1,911 5,687 5,803
Deferred income taxes (23,756 ) 4,168 (314,770 ) (80,388 )
Plugging and abandonment (2,506 ) (2,154 ) (5,222 ) (5,540 )
Loss on extinguishment of debt (12,455 )
Other, net (3,068 ) 3,059 (4,084 ) (231 )
Changes in current assets and liabilities 13,701   15,825   (36,642 ) 41,264  
Net cash provided by operating activities (GAAP) $ 158,139   $ 235,341   $ 415,012   $ 784,849  

 

(1) Adjusted EBITDAX represents net income (loss) before interest expense, other non-operating income or expense, income taxes, depletion, depreciation, amortization, and accretion expense, exploration expense, impairments, non-cash stock-based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, gains and losses on divestitures, and gains or losses on extinguishment of debt. 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 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 financial covenants under its Credit Agreement based on adjusted EBITDAX ratios. 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 (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Under the terms of the Company's credit agreement, if the Company fails to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a minimum permitted ratio of interest to adjusted EBITDAX, it will be in default, an event that would prevent it from borrowing under its credit facility and would therefore materially limit the Company's sources of liquidity. In addition, if the Company was in default under its credit facility and unable to obtain a waiver of that default from its lenders, the lenders under that facility and under the indentures governing the Company's outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for a default.

(2) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(3) Natural gas derivative settlements for the nine months ended September 30, 2015 include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015.
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
September 30, 2016
         

Total Capital Spend Reconciliation
(in thousands)
 

Reconciliation of costs incurred in oil & gas activities (GAAP) to total capital spend (Non-GAAP) (1)

For the Three Months Ended September 30,

For the Nine Months Ended September 30,

 
2016 2016
Costs incurred in oil and gas activities (GAAP): $ 156,445 $ 561,158
 
Less:
Asset retirement obligation (964 ) (2,684 )
Capitalized interest (4,511 ) (14,823 )
Proved property acquisitions (2) (542 ) (2,857 )
Unproved property acquisitions (4,020 ) (20,821 )
Other (977 ) (1,627 )
   
Total capital spend (Non-GAAP): $ 145,431   $ 518,346  

 

(1) The non-GAAP measure of total capital spend is presented because management believes it provides useful information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that total capital spend 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. Total capital spend should not be considered in isolation or as a substitute for Costs Incurred or other capital spending measures prepared under GAAP. The total capital spend amounts presented may not be comparable to similarly titled measures of other companies.

(2) Includes approximately $130,000 and $540,000 of ARO associated with proved property acquisitions for the three and nine month periods ended September 30, 2016, respectively.
 

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