News Release
 
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EXHIBIT 99.1
FOR IMMEDIATE RELEASE
November 2, 2017

SM ENERGY REPORTS THIRD QUARTER 2017 RESULTS
- PERMIAN PRODUCTION TAKES OFF
•
Permian production up 31% sequentially, and up 118% since 4Q16
•
Total production mix 32% oil; absolute oil production exceeded expectations
•
RockStar favorable new well results: three pads (eight wells) average peak 30-day IP rates of 1,191 Boe/d, 1,453 Boe/d and 1,333 Boe/d per well on each pad
•
Initiated Eagle Ford North JV to accelerate use of new technology and build value
•
Portfolio transition drives margin expansion, raising average realized price to $27.59 (pre-hedge), the highest level since 4Q14 despite sub-$50 oil
•
Liquidity remains strong at $1.4 billion

Denver, Colorado November 2, 2017 - SM Energy Company ("SM Energy" or the “Company”) (NYSE: SM) announced today financial results and operations highlights from the third quarter of 2017. This earnings release is accompanied by an investor presentation and pre-recorded call with transcript all posted to the Company’s website. Please visit the Company’s website at sm-energy.com to access this additional third quarter detail. The Company will host a webcast and conference call at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) tomorrow, November 3, 2017, to answer questions. Further information on the earnings webcast and conference call can be found below.
MANAGEMENT COMMENTARY
President and Chief Executive Officer Jay Ottoson comments: “The third quarter of 2017 marked a significant turning point in our transformation with a large increase in Permian production. In particular, our Howard County area wells in the Midland Basin, with high oil percentages and associated high margins, are generating outstanding returns, and continued delineation of our acreage in that area is yielding encouraging results.
“Overall, we are executing with excellence, resulting in a high level of capital efficiency as indicated by our higher than expected production and cash flows so far in 2017 (adjusted for divested/retained assets), despite lower commodity prices than anticipated, without change in our guided capital spending. Our operational performance keeps us on track to drive significant growth in cash flow, and we have substantial liquidity to fund our projected two-year cash flow outspend.
“We are also announcing today the signing of a joint venture agreement in a portion of our Eagle Ford North area that will result in a further increase in our capital efficiency. This partnership, which is similar to our existing Powder River Basin joint venture, will allow us to test new technologies and completion designs at varied well spacing on a portion of our acreage that does not currently generate substantial cash flow, potentially enhancing the asset value while reducing our required capital outlay for acreage holding.”

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THIRD QUARTER 2017 RESULTS
PRODUCTION
 
Oil
 
Natural Gas
 
NGLs
 
Total
 
MMBbls
 
Bcf
 
MMBbls
 
MMBoe
Permian
2.3

 
3.9

 
—

 
3.0

Eagle Ford
0.4

 
24.2

 
2.4

 
6.7

Rockies
0.7

 
1.0

 
—

 
1.0

Total
3.4

 
29.1

 
2.4

 
10.7

Third quarter production totaled 10.7 MMBoe, comprised of 32% oil, 45% natural gas and 23% NGLs. Oil production of 3.4 MMBbls exceeded the Company’s guidance, driven by a 31% sequential increase in Permian Basin production. As previously reported, natural gas and NGL production was affected early in September by Hurricane Harvey, which resulted in the curtailment of 0.2 MMBoe due to downstream, third party facilities that were impacted by the storm. Natural gas and NGL production was within the updated guidance despite further production curtailments late in the quarter that were predominantly due to severe rain storms in South Texas. During the last week of September, more than 18 inches of rain fell in portions of the Company’s Eagle Ford producing areas forcing the shut-in of a number of wells because certain roads were closed or impassable. Natural gas and NGL production was also affected by reduced working interests in certain wells due to the Eagle Ford North JV (discussed below). On a retained asset basis, third quarter production was up 7% compared with the third quarter of 2016. On a retained asset basis, for the first nine months of 2017, production was up 11% compared with the first nine months of 2016.
REALIZED PRICING
 
Oil
 
Natural Gas
 
NGLs
 
Average
 
$/Bbl
 
$/Mcf
 
$/Bbl
 
$/Boe
Permian
46.26
 
4.13
 
23.36
 
41.53
Eagle Ford
38.90
 
2.86
 
22.42
 
20.14
Rockies
44.87
 
1.09
 
20.71
 
36.87
Average Pre-Hedge
45.20
 
2.96
 
22.40
 
27.59
Average Post-Hedge
44.47
 
3.79
 
18.86
 
28.82
Benchmark pricing for the third quarter of 2017 was: WTI at $48.20 per barrel; NYMEX natural gas at $3.00 per MMBtu; and Hart Composite NGLs at $27.55 per barrel.
In the third quarter of 2017, the average realized price per Boe before the effects of commodity hedges was $27.59 per Boe, which is at its highest level since the fourth quarter of 2014 and demonstrates the margin expansion that results from the Company’s portfolio transition. Cash production costs totaled $11.49 per Boe, which included LOE of $4.81 per Boe (before ad valorem tax of $0.29 per Boe). Eagle Ford LOE per Boe came in above expectations largely due to non-recurring costs and lower overall volumes, while Permian LOE per Boe was down sequentially by approximately $1 as the Company gains efficiencies of scale with new wells coming on production. Transportation costs continued to decline, averaging $5.24 per Boe for the third quarter, as Permian production, which has low transportation costs, becomes an increasing portion of the production mix. Cash production costs are up 6.6% compared with the third quarter of 2016 and up 6.1% for the first nine months of 2017 compared with the first nine months of 2016.

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Net loss for the third quarter of 2017 was $89.1 million, or $0.80 per diluted common share, compared with a net loss of $40.9 million or $0.52 per diluted common share in the third quarter of 2016. Net loss in the third quarter of 2017 reflects a 25% decrease in production as a result of asset sales and a $44.4 million decrease in realized hedge gains, partially offset by a higher third quarter 2017 pre-hedge operating margin and lower depletion, depreciation and amortization expenses. The 2017 period also includes a loss on divestiture activity versus a gain in the prior year period.
Net cash provided by operating activities was $128.5 million in the third quarter of 2017 and $370.6 million for the first nine months of 2017.
As discussed below, adjusted EBITDAX, adjusted net income (loss) and adjusted net income (loss) per diluted common share are non-GAAP measures. Please reference the reconciliations to the most directly comparable GAAP financial measures at the end of this release.
Adjusted EBITDAX for the third quarter of 2017 was $164.5 million, which is up 7% sequentially predominantly due to the higher operating margin partially offset by lower production and lower realized derivative gains. Adjusted EBITDAX was down 20% from the prior year period. The prior year period benefited from higher production (prior to non-core asset sales) and significantly higher realized derivative gains. For the first nine months of 2017, adjusted EBITDAX was $490.7 million.
Adjusted net loss for the third quarter was $27.5 million, or $0.25 per diluted common share, compared with an adjusted net loss of $29.0 million, or $0.37 per diluted common share, in the third quarter of 2016. For the first nine months of 2017, adjusted net loss was $82.7 million, or $0.74 per diluted common share. 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, 2017, 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, with zero drawn on the Company’s senior secured credit facility. At quarter-end, the Company had a cash balance of $441.4 million, providing for net debt of $2.5 billion. The Company’s undrawn credit facility plus cash on hand provided $1.4 billion in liquidity.
CAPITAL ACTIVITY AND OPERATIONS
Please refer to the Total Capital Spend Reconciliation at the end of this release for a reconciliation to Costs Incurred in oil and gas activities (GAAP).
Costs incurred for the third quarter of 2017 were $226.6 million. Third quarter total capital spend was $226.8 million. During the quarter, the Company drilled or participated in 31 net wells and completed or participated in 28 net wells. For the first nine months of 2017, costs incurred were $741.6 million and total capital spend was $657.0 million. Year-to-date, the Company has drilled or participated in 88 net wells and completed or participated in 87 net wells.
PERMIAN - MIDLAND BASIN
In the third quarter of 2017, production from the Company’s Midland Basin assets was 3.0 MMBoe and was 78% oil. Midland Basin production is up 31% sequentially as the Company had 23 (operated) flowing completions in the quarter. The Company is currently running seven horizontal rigs in the basin, with one in the Sweetie Peck area and six in the RockStar area, and plans to add an eighth rig to the area by year-end.

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The Company recently added a fourth completions crew to the area. The third quarter production margin for the Midland Basin assets was $30.62 per Boe.
The Company’s Midland Basin operations continue to be characterized by high capital efficiency and strong well performance. New well results include the Iceman and Griswold pads, each drilled at 420 foot well spacing. At the Iceman pad, three Wolfcamp A wells averaged a peak 30-day rate of 1,453 Boe/d per well (Lower Spraberry wells also producing on the Iceman pad have not yet reached a peak rate), and at the three-well Griswold pad, located on the south-east flank of the Company’s RockStar acreage, the Wolfcamp A wells averaged a peak 30-day rate of 1,191 Boe/d per well. At the Jester pad, one Wolfcamp A and one Wolfcamp B well averaged a peak 30-day rate of 1,333 Boe/d per well. (Please refer to the 3Q17 Earnings Presentation for further detail on new well results). Capital efficiency is evidenced by several drilling and completion metrics. For example, the Company is currently drilling at an average rate of 1,100 feet per day (based on spud to rig release), which is up approximately 14% from the second quarter and places the Company in the top quartile among Midland Basin operators. Completions operations have achieved pumping efficiencies of more than 80% as a result of excellent performance from the Company’s pumping service providers.
The Company currently has approximately 89,000 net acres in the Midland Basin, which includes approximately 5,000 net acres acquired year-to-date through acreage trades and other transactions.
EAGLE FORD
In the third quarter of 2017, production from the Company’s Eagle Ford assets was 6.7 MMBoe and included 60% natural gas, 35% NGLs, and 5% oil. Third quarter production was affected by curtailments following Hurricane Harvey and a second storm late in the quarter, as well as a reduction in the Company's working interest in new wells as a result of the Eagle Ford North JV (see below). The Company is currently running two horizontal rigs in the area and no completions crews. The Company drilled six and completed four net wells in the third quarter (all completions were part of the Eagle Ford North JV) and drilled 17 and completed 35 net wells in the area in the first nine months of 2017.
The Company has approximately 165,000 net acres in its operated Eagle Ford program.
EAGLE FORD NORTH JOINT VENTURE
In September 2017, the Company entered into a joint venture (JV) agreement with a third party to drill 16 wells and complete 23 wells in a focused portion of its Eagle Ford North area. This partnership allows the Company to use third party resources to test cutting edge technology, accelerate the capture of technical data and hold acreage in this area, potentially expanding economic drilling inventory and acreage value. Moreover, the Company expects this partnership will result in further optimizations outside of the JV area, enhancing the overall value of its Eagle Ford asset. The objectives of this agreement are similar to the Company’s highly successful, ongoing JV arrangement in the Powder River Basin. Per the terms of the agreement, the Company’s working interest was reduced in seven wells completed during the quarter, which affected Eagle Ford production by approximately (0.1) MMBoe for the quarter. The partnership expects to drill six carried wells in the area in the fourth quarter of 2017. The effect of the partnership on fourth quarter production is estimated at up to (0.5) MMBoe, depending upon actual well performance.

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GUIDANCE
Full year 2017 guidance is revised as follows:
 
Full Year 2017
 
Implied 4Q17 at Midpoint
Total Capital Spend
~$875 MM
unchanged
~$218 MM
Total Production
44.2-44.6 MMBoe
updated: to reflect Eagle Ford storm effects and JV; 4Q planned shut-ins Rockies and Eagle Ford, related to workovers and offset operator activity

10.1-10.5 MMBoe
Percent Oil in Mix
~30%
slightly increased
~35%
LOE (including ad valorem tax)
$4.60-4.80/Boe
additional storm related costs in 4Q; lower Eagle Ford volumes
$5.20/Boe
Transportation
$5.40-5.60/Boe
narrowed
$5.00/Boe
Production Taxes
4.0-4.5%
unchanged
 
G&A (includes ~$20MM non-cash, stock-based comp expense)
$116-120 MM
reduced
$32.4 MM
Exploration/capitalized overhead (wholly included in capital spend)
~$55-60 MM
reclassified certain amounts within total capital spend
$18.2 MM
DD&A
$12-14/Boe
unchanged
$14.66/Boe
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.
COMMODITY DERIVATIVES
As of November 1, 2017.
The Company remains well-hedged into the fourth quarter of 2017 with approximately 80% of production hedged (at the mid-point of guidance). For 2018, hedged volumes are approximately 31 MMBoe, of which 36% is oil, 39% is natural gas and 25% is NGLs.

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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)
 
 
 
 
 
4Q17
1,510/$47.11
1,086/$56.05 - $47.51
22,001/$3.98
2,210/$22.05
 
 
 
 
 
1Q18
1,075/$50.16
1,026/$58.46 - $50.00
20,788/$3.25
2,113/$31.07
 
 
 
 
 
2Q18
1,534/$49.57
1,004/$58.37 - $50.00
15,712/$2.85
1,642/$28.08
 
 
 
 
 
3Q18
1,769/$49.77
1,393/$57.93 - $50.00
17,147/$2.88
1,831/$28.14
 
 
 
 
 
4Q18
1,894/$49.87
1,607/$57.75 - $50.00
18,646/$2.91
2,021/$28.13
Notes: The volumes above represent fixed swap and collar contracts the Company has in place through 4Q18. Volumes for 4Q17 include all commodity contracts for settlement any time during the fourth quarter of 2017; 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. 2017 and 2018 quarters include ethane, propane, butanes and gasoline. In addition to the volumes above, the Company has oil basis swaps in place. See 3Q17 Earnings Presentation for contract details on the oil basis swaps.
UPCOMING EVENTS
EARNINGS WEBCAST AND CALL
As previously announced, SM Energy is posting a pre-recorded discussion and presentation in conjunction with this earnings release. Please look for the additional detail on our website at www.sm-energy.com. Tomorrow morning, the Company will host a third quarter financial and operating results Q&A session via webcast and conference call. Please join management at 8:00 a.m. Mountain Time/10:00 a.m. Eastern Time November 3, 2017. Join us via webcast at www.sm-energy.com or by telephone 877-870-4263 (toll free) or 412-317-0790 (international), and indicate SM Energy earnings call. The webcast and call will also be available for replay. The dial-in replay number is 877-344-7529 (toll free), and the replay access code is 10112207.
UPCOMING CONFERENCE PARTICIPATION
•
November 8, 2017 - Baird 47th Annual Industrial Conference. Chief Financial Officer Wade Pursell will present at 2:30 p.m. Central time. This event will be webcast. An investor presentation for this event will be posted to the Company’s website on November 7, 2017.
•
November 14, 2017 - KLR E&P Conference Denver. President and Chief Executive Officer Jay Ottoson will present at 12:05 p.m. Mountain time. This event will not be webcast.
•
November 29, 2017 - BAML Leveraged Finance Conference. Chief Financial Officer Wade Pursell will present at 10:50 a.m. Eastern time. This event will be webcast. An investor presentation for this event will be posted to the Company’s website on November 28, 2017.
•
December 6, 2017 - Capital One Securities 12th Annual Energy Conference. President and Chief Executive Officer Jay Ottoson will present at 1:30 p.m. Central time. This event will be webcast.


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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, projected changes in production volumes and cash flows and the expected benefits from joint venture arrangements. General risk factors include 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 natural gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results, including from pilot tests; the uncertain nature of expected benefits from the actual or expected acquisition, 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 and quality 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 2016 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 CONTACTS
INVESTORS: Jennifer Martin Samuels, jsamuels@sm-energy.com, 303-864-2507









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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
For the Three Months Ended 
 September 30,
 
For the Nine Months Ended 
 September 30,
Production Data
2017
 
2016
 
Percent Change
 
2017
 
2016

Percent Change
Average realized sales price, before the effects of derivative settlements:
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
45.20

 
$
38.81

 
16
 %
 
$
45.77

 
$
34.69

 
32
 %
Gas (per Mcf)
2.96

 
2.71

 
9
 %
 
2.98

 
2.12

 
41
 %
NGLs (per Bbl)
22.40

 
16.58

 
35
 %
 
21.36

 
14.91

 
43
 %
Equivalent (per BOE)
$
27.59

 
$
23.25

 
19
 %
 
$
26.76

 
$
19.87

 
35
 %
Average realized sales price, including the effects of derivative settlements:
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
44.47

 
$
50.15

 
(11
)%
 
$
44.32

 
$
52.31

 
(15
)%
Gas (per Mcf)
3.79

 
2.98

 
27
 %
 
3.63

 
2.86

 
27
 %
NGLs (per Bbl)
18.86

 
16.08

 
17
 %
 
18.93

 
15.12

 
25
 %
Equivalent (per BOE)
$
28.82

 
$
27.31

 
6
 %
 
$
27.62

 
$
27.18

 
2
 %
Production:
 
 
 
 
 
 
 
 
 
 
 
Oil (MMBbl)
3.4

 
4.3

 
(21
)%
 
9.8

 
12.6

 
(22
)%
Gas (Bcf)
29.1

 
37.1

 
(22
)%
 
97.0

 
111.7

 
(13
)%
NGLs (MMBbl)
2.4

 
3.6

 
(34
)%
 
8.1

 
10.7

 
(24
)%
MMBOE (6:1)
10.7

 
14.2

 
(25
)%
 
34.1

 
41.9

 
(19
)%
Average daily production:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbl/d)
37.1

 
47.2

 
(21
)%
 
36.1

 
45.9

 
(21
)%
Gas (MMcf/d)
316.1

 
403.0

 
(22
)%
 
355.4

 
407.8

 
(13
)%
NGLs (MBbl/d)
26.2

 
39.5

 
(34
)%
 
29.6

 
39.0

 
(24
)%
MBOE/d (6:1)
116.0

 
153.9

 
(25
)%
 
124.9

 
152.9

 
(18
)%
Per BOE data:
 
 
 
 
 
 
 
 
 
 
 
Realized price, before the effects of derivative settlements
$
27.59

 
$
23.25

 
19
 %
 
$
26.76

 
$
19.87

 
35
 %
Lease operating expense
4.81

 
3.29

 
46
 %
 
4.22

 
3.46

 
22
 %
Transportation costs
5.24

 
6.24

 
(16
)%
 
5.62

 
6.08

 
(8
)%
Production taxes
1.15

 
1.04

 
11
 %
 
1.11

 
0.88

 
26
 %
Ad valorem tax expense
0.29

 
0.21

 
38
 %
 
0.34

 
0.22

 
55
 %
General and administrative (excluding stock-compensation)
2.16

 
1.96

 
10
 %
 
2.15

 
1.85

 
16
 %
Net, before the effects of derivative settlements
$
13.94

 
$
10.51

 
33
 %
 
$
13.32

 
$
7.38

 
80
 %
Derivative settlement gain
1.23

 
4.06

 
(70
)%
 
0.86

 
7.31

 
(88
)%
Margin, including the effects of derivative settlements
$
15.17

 
$
14.57

 
4
 %
 
$
14.18

 
$
14.69

 
(3
)%
 
 
 
 
 
 
 
 
 
 
 
 
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion
$
12.61

 
$
13.70

 
(8
)%
 
$
12.48

 
$
14.78

 
(16
)%


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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
Condensed Consolidated Balance Sheets
 
 
 
(in thousands, except share amounts)
September 30,
 
December 31,
 ASSETS
2017
 
2016
Current assets:
 
 
 
Cash and cash equivalents
$
441,415

 
$
9,372

Accounts receivable
146,056

 
151,950

Derivative asset
63,685

 
54,521

Prepaid expenses and other
17,756

 
8,799

Total current assets
668,912

 
224,642

 
 
 
 
Property and equipment (successful efforts method):
 
 
 
Proved oil and gas properties
5,938,351

 
5,700,418

Less - accumulated depletion, depreciation, and amortization
(3,243,072
)
 
(2,836,532
)
Unproved oil and gas properties
2,321,508

 
2,471,947

Wells in progress
287,106

 
235,147

Oil and gas properties held for sale, net
7,144

 
372,621

Other property and equipment, net of accumulated depreciation of $50,468 and $42,882, respectively
106,046

 
137,753

Total property and equipment, net
5,417,083

 
6,081,354

 
 
 
 
Noncurrent assets:
 
 
 
Derivative asset
60,035

 
67,575

Other noncurrent assets
32,896

 
19,940

Total other noncurrent assets
92,931

 
87,515

Total Assets
$
6,178,926

 
$
6,393,511

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
348,885

 
$
299,708

Derivative liability
87,791

 
115,464

Total current liabilities
436,676

 
415,172

 
 
 
 
Noncurrent liabilities:
 
 
 
Revolving credit facility
—

 
—

Senior Notes, net of unamortized deferred financing costs
2,768,346

 
2,766,719

Senior Convertible Notes, net of unamortized discount and deferred financing costs
137,012

 
130,856

Asset retirement obligation
100,958

 
96,134

Asset retirement obligation associated with oil and gas properties held for sale
—

 
26,241

Deferred income taxes
208,720

 
315,672

Derivative liability
67,676

 
98,340

Other noncurrent liabilities
47,497

 
47,244

Total noncurrent liabilities
3,330,209

 
3,481,206

 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,624,029 and 111,257,500 shares, respectively
1,116

 
1,113

Additional paid-in capital
1,734,217

 
1,716,556

Retained earnings
691,915

 
794,020

Accumulated other comprehensive loss
(15,207
)
 
(14,556
)
Total stockholders’ equity
2,412,041

 
2,497,133

Total Liabilities and Stockholders’ Equity
$
6,178,926

 
$
6,393,511


9



 
 
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SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
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,
 
2017
 
2016
 
2017
 
2016
Operating revenues and other income:
 
 
 
 
 
 
 
Oil, gas, and NGL production revenue
$
294,459

 
$
329,165

 
$
912,596

 
$
832,130

Net gain (loss) on divestiture activity
(1,895
)
 
22,388

 
(131,565
)
 
3,413

Other operating revenues
2,815

 
1,107

 
7,807

 
2,007

Total operating revenues and other income
295,379

 
352,660

 
788,838

 
837,550

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Oil, gas, and NGL production expense
122,651

 
152,524

 
385,073

 
445,658

Depletion, depreciation, amortization, and asset retirement obligation liability accretion
134,599

 
193,966

 
425,643

 
619,193

Exploration
14,243

 
13,482

 
39,293

 
41,942

Impairment of proved properties
—

 
8,049

 
3,806

 
277,834

Abandonment and impairment of unproved properties
—

 
3,568

 
157

 
5,917

General and administrative(1)
27,880

 
32,679

 
85,564

 
93,117

Net derivative (gain) loss(2)
80,599

 
(28,037
)
 
(89,364
)
 
121,086

Other operating expenses, net
999

 
(5,917
)
 
6,303

 
7,731

Total operating expenses
380,971

 
370,314

 
856,475

 
1,612,478

 
 
 
 
 
 
 
 
Loss from operations
(85,592
)
 
(17,654
)
 
(67,637
)
 
(774,928
)
 
 
 
 
 
 
 
 
Non-operating income (expense):
 
 
 
 
 
 
 
Interest expense
(44,091
)
 
(47,206
)
 
(135,639
)
 
(112,329
)
Gain (loss) on extinguishment of debt
—

 
—

 
(35
)
 
15,722

Other, net
1,301

 
221

 
2,901

 
232

 
 
 
 
 
 
 
 
Loss before income taxes
(128,382
)
 
(64,639
)
 
(200,410
)
 
(871,303
)
Income tax benefit
39,270

 
23,732

 
65,825

 
314,505

 
 
 
 
 
 
 
 
Net loss
$
(89,112
)
 
$
(40,907
)
 
$
(134,585
)
 
$
(556,798
)
 
 
 
 
 
 
 
 
Basic weighted-average common shares outstanding
111,575

 
78,468

 
111,366

 
71,574

Diluted weighted-average common shares outstanding
111,575

 
78,468

 
111,366

 
71,574

Basic net loss per common share
$
(0.80
)
 
$
(0.52
)
 
$
(1.21
)
 
$
(7.78
)
Diluted net loss per common share
$
(0.80
)
 
$
(0.52
)
 
$
(1.21
)
 
$
(7.78
)
 
 
 
 
 
 
 
 
(1) Non-cash stock-based compensation component included in:
 
 
 
 
 
 
 
Exploration expense
$
1,495

 
$
1,590

 
$
3,898

 
$
5,037

G&A expense
$
4,852

 
$
4,980

 
$
12,262

 
$
15,448

 
 
 
 
 
 
 
 
(2)  The net derivative (gain) loss line item consists of the following:
 
 
 
 
 
 
 
Settlement gain
$
(13,092
)
 
$
(57,496
)
 
$
(29,402
)
 
$
(306,234
)
(Gain) loss on fair value changes
$
93,691

 
$
29,459

 
$
(59,962
)
 
$
427,320

Total net derivative (gain) loss
$
80,599

 
$
(28,037
)
 
$
(89,364
)
 
$
121,086


10



 
 
smelogotall4c850p3a02.jpg

SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
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, 2016
111,257,500

 
$
1,113

 
$
1,716,556

 
$
794,020

 
$
(14,556
)
 
$
2,497,133

Net loss
—

 
—

 
—

 
(134,585
)
 
—

 
(134,585
)
Other comprehensive loss
—

 
—

 
—

 
—

 
(651
)
 
(651
)
Dividends, $0.10 per share
—

 
—

 
—

 
(11,144
)
 
—

 
(11,144
)
Issuance of common stock under Employee Stock Purchase Plan
123,678

 
1

 
1,737

 
—

 
—

 
1,738

Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings
171,278

 
1

 
(1,241
)
 
—

 
—

 
(1,240
)
Stock-based compensation expense
71,573

 
1

 
16,159

 
—

 
—

 
16,160

Cumulative effect of accounting change
—

 
—

 
1,108

 
43,624

 
—

 
44,732

Other
—

 
—

 
(102
)
 
—

 
—

 
(102
)
Balances, September 30, 2017
111,624,029

 
$
1,116

 
$
1,734,217

 
$
691,915

 
$
(15,207
)
 
$
2,412,041



11



 
 
smelogotall4c850p3a02.jpg

SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
Condensed Consolidated Statements of Cash Flows
 
 
 
 
 
 
(in thousands)
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
 
2017
 
2016
 
2017
 
2016
Cash flows from operating activities:
 
 
 
 
 
 
 
Net loss
$
(89,112
)
 
$
(40,907
)
 
$
(134,585
)
 
$
(556,798
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
 
Net (gain) loss on divestiture activity
1,895

 
(22,388
)
 
131,565

 
(3,413
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
134,599

 
193,966

 
425,643

 
619,193

Impairment of proved properties
—

 
8,049

 
3,806

 
277,834

Abandonment and impairment of unproved properties
—

 
3,568

 
157

 
5,917

Stock-based compensation expense
6,347

 
6,570

 
16,160

 
20,485

Net derivative (gain) loss
80,599

 
(28,037
)
 
(89,364
)
 
121,086

Derivative settlement gain
13,092

 
57,496

 
29,402

 
306,234

Amortization of debt discount and deferred financing costs
3,799

 
3,757

 
12,478

 
5,687

Non-cash (gain) loss on extinguishment of debt, net
—

 
—

 
22

 
(15,722
)
Deferred income taxes
(36,668
)
 
(23,756
)
 
(67,458
)
 
(314,770
)
Plugging and abandonment
(486
)
 
(2,506
)
 
(2,095
)
 
(5,222
)
Other, net
2,446

 
(11,374
)
 
4,713

 
(8,857
)
Changes in current assets and liabilities:
 
 
 
 
 
 
 
Accounts receivable
(25,491
)
 
12,441

 
21,502

 
1,221

Prepaid expenses and other
366

 
(835
)
 
(8,955
)
 
7,652

Accounts payable and accrued expenses
30,533

 
(3,439
)
 
21,560

 
(65,166
)
Accrued derivative settlements
6,563

 
5,534

 
6,046

 
19,651

Net cash provided by operating activities
128,482

 
158,139

 
370,597

 
415,012

 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
Net proceeds from the sale of oil and gas properties
12,118

 
188,862

 
778,365

 
201,829

Capital expenditures
(258,226
)
 
(147,224
)
 
(624,969
)
 
(492,794
)
Acquisition of proved and unproved oil and gas properties
751

 
(4,102
)
 
(87,389
)
 
(21,853
)
Acquisition deposit held in escrow
—

 
(49,000
)
 
3,000

 
(49,000
)
Other, net
—

 
900

 
—

 
—

Net cash provided by (used in) investing activities
(245,357
)
 
(10,564
)
 
69,007

 
(361,818
)
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from credit facility
—

 
158,000

 
406,000

 
743,000

Repayment of credit facility
—

 
(488,500
)
 
(406,000
)
 
(945,000
)
Debt issuance costs related to credit facility
—

 
—

 
—

 
(3,132
)
Net proceeds from Senior Notes
—

 
492,397

 
—

 
492,397

Cash paid to repurchase Senior Notes
—

 
—

 
(2,344
)
 
(29,904
)
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

 
1,738

 
533,266

Dividends paid
—

 
—

 
(5,563
)
 
(3,404
)
Other, net
(1,231
)
 
(2,308
)
 
(1,392
)
 
(2,341
)
Net cash provided by (used in) financing activities
(1,231
)
 
833,073

 
(7,561
)
 
927,454

 
 
 
 
 
 
 
 
Net change in cash and cash equivalents
(118,106
)
 
980,648

 
432,043

 
980,648

Cash and cash equivalents at beginning of period
559,521

 
18

 
9,372

 
18

Cash and cash equivalents at end of period
$
441,415

 
$
980,666

 
$
441,415

 
$
980,666


12



 
 
smelogotall4c850p3a02.jpg

SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
Adjusted EBITDAX(1)
 
 
 
 
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of net 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,
 
2017
 
2016
 
2017
 
2016
Net loss (GAAP)
$
(89,112
)
 
$
(40,907
)
 
$
(134,585
)
 
$
(556,798
)
Interest expense
44,091

 
47,206

 
135,639

 
112,329

Other non-operating income, net
(1,301
)
 
(221
)
 
(2,901
)
 
(232
)
Income tax benefit
(39,270
)
 
(23,732
)
 
(65,825
)
 
(314,505
)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
134,599

 
193,966

 
425,643

 
619,193

Exploration(2)
12,748

 
11,892

 
35,395

 
36,905

Impairment of proved properties
—

 
8,049

 
3,806

 
277,834

Abandonment and impairment of unproved properties
—

 
3,568

 
157

 
5,917

Stock-based compensation expense
6,347

 
6,570

 
16,160

 
20,485

Net derivative (gain) loss
80,599

 
(28,037
)
 
(89,364
)
 
121,086

Derivative settlement gain
13,092

 
57,496

 
29,402

 
306,234

Net (gain) loss on divestiture activity
1,895

 
(22,388
)
 
131,565

 
(3,413
)
(Gain) loss on extinguishment of debt
—

 
—

 
35

 
(15,722
)
Other
785

 
(8,314
)
 
5,620

 
(4,757
)
Adjusted EBITDAX (Non-GAAP)
$
164,473

 
$
205,148

 
$
490,747

 
$
604,556

Interest expense
(44,091
)
 
(47,206
)
 
(135,639
)
 
(112,329
)
Other non-operating income, net
1,301

 
221

 
2,901

 
232

Income tax benefit
39,270

 
23,732

 
65,825

 
314,505

Exploration(2)
(12,748
)
 
(11,892
)
 
(35,395
)
 
(36,905
)
Amortization of debt discount and deferred financing costs
3,799

 
3,757

 
12,478

 
5,687

Deferred income taxes
(36,668
)
 
(23,756
)
 
(67,458
)
 
(314,770
)
Plugging and abandonment
(486
)
 
(2,506
)
 
(2,095
)
 
(5,222
)
Other, net
1,661

 
(3,060
)
 
(920
)
 
(4,100
)
Changes in current assets and liabilities
11,971

 
13,701

 
40,153

 
(36,642
)
Net cash provided by operating activities (GAAP)
$
128,482

 
$
158,139

 
$
370,597

 
$
415,012

 
 
 
 
 
 
 
 
(1) Adjusted EBITDAX represents net loss before interest expense, other non-operating income and expense, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe 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 we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our 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 other 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. Our credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of senior secured debt to adjusted EBITDAX and a minimum permitted ratio of adjusted EBITDAX to interest, we would be in default, an event that would prevent us from borrowing under our credit facility and would therefore materially limit our sources of liquidity. In addition, if we are in default under our credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing our outstanding Senior Notes and Senior Convertible Notes would be entitled to exercise all of their remedies for 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 Company's condensed consolidated statements of operations for the component of stock-based compensation expense recorded to exploration expense.



13



 
 
smelogotall4c850p3a02.jpg

SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
Adjusted Net Loss (Non-GAAP)
 
 
 
 
 
 
 
(in thousands, except per share data)
 
 
 
 
 
 
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
 
2017
 
2016
 
2017
 
2016
Net loss (GAAP)
$
(89,112
)
 
$
(40,907
)
 
$
(134,585
)
 
$
(556,798
)
Net derivative (gain) loss
80,599

 
(28,037
)
 
(89,364
)
 
121,086

Derivative settlement gain
13,092

 
57,496

 
29,402

 
306,234

Net (gain) loss on divestiture activity
1,895

 
(22,388
)
 
131,565

 
(3,413
)
Impairment of proved properties
—

 
8,049

 
3,806

 
277,834

Abandonment and impairment of unproved properties
—

 
3,568

 
157

 
5,917

(Gain) loss on extinguishment of debt
—

 
—

 
35

 
(15,722
)
Termination fee on temporary second lien facility
—

 
10,000

 
—

 
10,000

Other, net(2)
785

 
(10,008
)
 
5,620

 
(7,425
)
Tax effect of adjustments(1)
(34,790
)
 
(6,818
)
 
(29,321
)
 
(253,497
)
Adjusted net loss (Non-GAAP)(3)
$
(27,531
)
 
$
(29,045
)
 
$
(82,685
)
 
$
(115,784
)
 
 
 
 
 
 
 
 
Diluted net loss per common share (GAAP)
$
(0.80
)
 
$
(0.52
)
 
$
(1.21
)
 
$
(7.78
)
Net derivative (gain) loss
0.72

 
(0.36
)
 
(0.80
)
 
1.69

Derivative settlement gain
0.12

 
0.73

 
0.27

 
4.28

Net (gain) loss on divestiture activity
0.02

 
(0.29
)
 
1.18

 
(0.05
)
Impairment of proved properties
—

 
0.10

 
0.03

 
3.88

Abandonment and impairment of unproved properties
—

 
0.05

 
—

 
0.08

(Gain) loss on extinguishment of debt
—

 
—

 
—

 
(0.22
)
Termination fee on temporary second lien facility
—

 
0.13

 
—

 
0.14

Other, net(2)
—

 
(0.12
)
 
0.05

 
(0.10
)
Tax effect of adjustments(1)
(0.31
)
 
(0.09
)
 
(0.26
)
 
(3.54
)
Adjusted net loss per diluted common share (Non-GAAP)(4)
$
(0.25
)
 
$
(0.37
)
 
$
(0.74
)
 
$
(1.62
)
 
 
 
 
 
 
 
 
Diluted weighted-average common shares outstanding (GAAP)
111,575

 
78,468

 
111,366

 
71,574

 
 
 
 
 
 
 
 
(1) The tax effect of adjustments is calculated using a tax rate of 36.1% for the three-month and nine-month periods ended September 30, 2017, and a tax rate of 36.5% for the three-month and nine-month periods ended September 30, 2016. These rates approximate the Company's statutory tax rate for the respective periods, as adjusted for ordinary permanent differences.
(2) For the three-month and nine-month periods ended September 30, 2017, the adjustment is related to impairment on materials inventory, the change in Net Profits Plan liability, and bad debt expense. For the three-month and nine-month periods ended September 30, 2016, the adjustment relates to the change in Net Profits Plan liability, impairment of materials inventory, and an adjustment relating 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 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 derivative gains and losses net of settlements, impairments, net (gain) loss on divestiture activity, materials inventory loss, and gains or losses on extinguishment of debt. 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 adjusted net loss, basic weighted-average common shares outstanding are used in the calculation of adjusted net loss per diluted common share.

14



 
 
smelogotall4c850p3a02.jpg

SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (UNAUDITED)
September 30, 2017
 
 
 
 
Total Capital Spend Reconciliation
 
 
 
(in millions)
 
 
 
 
 
 
 
Reconciliation of costs incurred in oil & gas activities (GAAP) to total capital spend (Non-GAAP)(1)(3)
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
 
2017
 
2017
Costs incurred in oil and gas activities (GAAP):
$
226.6

 
$
741.6

Asset retirement obligation
0.4

 
(1.0
)
Capitalized interest
(3.5
)
 
(8.6
)
Proved property acquisitions(2)
0.4

 
(1.0
)
Unproved property acquisitions
—

 
(75.6
)
Other
2.9

 
1.6

Total capital spend (Non-GAAP):
$
226.8

 
$
657.0

 
 
 
 
(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 $0 and $887,000 of ARO associated with proved property acquisitions for the three and nine months ended September 30, 2017, respectively.
(3) The Company completed several primarily non-monetary acreage trades in the Midland Basin during the first nine months of 2017 totaling $283.7 million of value attributed to the properties surrendered. This non-monetary consideration is not reflected in the costs incurred or capital spend amounts presented above.


15