SM Energy Reports 2017 Results And 2018 Operating Plan: Permian Execution Outstanding, Cash Flow Growth Ahead
DENVER, Feb. 21, 2018 /PRNewswire/ -- SM Energy Company ("SM Energy" or the "Company") (NYSE: SM) today announces fourth quarter and full year 2017 financial and operating results, year-end 2017 reserves and the Company's 2018 operating plan. Highlights include:
-- 2017 net production totaled 44.5 MMBoe, delivering 165% production
growth from top tier Midland Basin assets and 47% operating margin
growth per Boe 4Q16 to 4Q17 as the Company successfully continues its
portfolio transition.
-- 2017 year-end proved reserves increased to 468 MMBoe, adding 47% reserve
growth on a retained asset basis, nearly tripling Midland Basin reserves
and increasing the standardized measure of discounted future net cash
flows by 2.5 times from $1.2B to $3.0B.
-- 2018-2019 operating plan targets competitive growth in debt adjusted
cash flow and aligns expected total capital spend with expected cash
flow by mid-year 2019.
-- Outstanding performance from new wells in Howard County ranks SM top
Midland Basin operator by revenue per well and results in significant
value creation on RockStar properties. New RockStar wells announced
today include two Maverick pad wells with 30-day IP rates that each
approximated 200 Boe/d per 1,000 lateral feet, continuing the Company's
strong performance record.
MANAGEMENT COMMENTARY
President and Chief Executive Officer Jay Ottoson comments: "At this time last year we set forth an aggressive three-year plan to grow debt adjusted cash flow --our preferred measure of returns-- implementing a strategy that included driving value creation on our newly acquired Howard County assets through optimizing drilling and completion operations, generating margin expansion through a capital program focused on growth on our Midland Basin assets, and further coring up our portfolio to maximize the present value of assets and de-lever the balance sheet. 2017 was a highly successful year in meeting and exceeding our announced objectives, and I thank our SM team across the board for successful execution.
"We commence 2018 well positioned to continue this strategy and meet our planned growth trajectory. While 2017 was a transitional year for production and cash flow growth, 2018 and 2019 target substantial growth in cash flow along with a reduction in net debt:EBITDAX to approximately 2.5 times. This year we move into development mode on our RockStar assets. We have increased the rig count in the Midland Basin from four in early 2017 to nine currently, while continuing to demonstrate top tier efficiency metrics. I believe our operations are top tier as is our asset base, and we look forward to generating increased value for our shareholders in 2018 and beyond."
"Lastly, I want to congratulate Jennifer Martin Samuels on her well deserved promotion to Vice President - Investor Relations in recognition of her outstanding work in leading our investor relations efforts."
2017 IN REVIEW
YEAR-END 2017 PROVED RESERVES
Year-end 2017 proved reserves of 468 MMBoe are calculated in accordance with SEC pricing at $51.34 per barrel of oil NYMEX, $3.00 per MMBtu of natural gas at Henry Hub, and $27.69 per barrel of NGLs at Mt. Belvieu. Year-end proved reserves were 34% oil, 20% NGLs and 46% natural gas. Proved reserves were 46% proved developed.
-- Adjusting year-end 2016 reserves for divestitures, proved reserves
increased 47% on a retained asset basis.
-- Net proved reserve additions were 192 MMBoe, or 4.3 times production.
-- Midland Basin proved reserves nearly tripled to 160 MMBoe.
The table below provides a reconciliation of changes in the Company's proved reserves from year-end 2016 to year-end 2017 (numbers are rounded):
Proved reserves year-end 2016
(MMBoe) 396
Divestitures completed in 2017 (76)
---
Proved reserves 2016 pro forma
sold properties 320
Production (44)
Reserve additions from drilling
and performance 182
Reserve additions through
acquisition 1
Reserve revisions net of price
and 5-year rules 9
---
Proved reserves year-end 2017
(MMBoe) 468
Proved reserves at year-end include approximately 4.2 MMBoe associated with the announced agreement to sell certain Powder River Basin assets.
The standardized measure of discounted future net cash flows was $3.0 billion at year-end 2017, up from $1.2 billion at year-end 2016. PV-10 (a non-GAAP measure, reconciled to the standardized measure, see Financial Highlights below) was up more than 2.5 times at $3.1 billion at year-end 2017, compared with $1.2 billion at year-end 2016.
FOURTH QUARTER AND FULL YEAR RESULTS
See the Financial Highlights section below for production and per Boe detail, summary financial statements and non-GAAP reconciliations.
Production volumes for the fourth quarter and full year 2017 were:
PRODUCTION
Fourth Quarter 2017 Full Year 2017
------------------- --------------
Oil (MMBbls) 3.9 13.7
Natural gas (Bcf) 26.0 123.0
NGLs (MMBbls) 2.2 10.3
Total MMBoe 10.4 44.5
==== ====
By region:
REGIONAL PRODUCTION
Fourth Quarter 2017 Full Year 2017
------------------- --------------
Eagle Ford 6.0 29.5
Permian Basin 3.6 11.0
Rocky Mountain 0.8 4.1
Total MMBoe 10.4 44.5
==== ====
Amounts may not calculate due to rounding
Eagle
Ford includes nominal other production from the
region; full year includes non-operated Eagle
Ford production prior to divestiture
For
purposes of 2017 presentation, retained assets
include Powder River Basin assets expected to be
sold in 2018
-- Production increased 2% and 8% for the fourth quarter and full year,
respectively, compared with the prior year periods on a retained asset
basis.
-- Oil production increased 51% and 52% for the fourth quarter and full
year, respectively, compared with the prior year periods on a retained
asset basis.
-- Production in the fourth quarter reflects strong 21% sequential growth
in Permian Basin volumes, which was more than offset by lower sequential
Eagle Ford volumes as a result of the previously announced joint venture
as well as natural declines, as no new wells were completed in the Eagle
Ford during the quarter.
Realized prices (before and after the effect of derivative settlements) for the fourth quarter and full year 2017 were:
COMMODITY PRICES
4Q17 Full Year 2017
Pre/post Hedge Pre/post Hedge
-------------- --------------
Oil - $/Bbl 53.32/48.90 47.88/45.60
Natural gas - $/Mcf 3.09/4.03 3.00/3.72
NGLs - $/Bbl 26.01/18.84 22.35/18.91
Boe - $/Boe 32.95/32.16 28.20/28.68
----------- -----------
-- Pre-hedge realized prices of $32.95 per Boe and $28.20 per Boe for the
two periods presented were up 27% and 32%, respectively, from the prior
year periods demonstrating the revenue benefit from increasing the
proportion of production from the oil-rich Midland Basin and improved
benchmark commodity prices. Oil, natural gas and NGL revenue was up in
2017 versus 2016, despite a 20% decline in total production.
-- Cash derivative settlements for NGLs were a loss of $15.8 million in the
fourth quarter, as the benchmark NGL price jumped to a 13-quarter high.
Operating costs for the fourth quarter and full year were:
OPERATING COSTS $ PER BOE
Fourth Quarter 2017 Full Year 2017
------------------- --------------
Total LOE, incl. ad
valorem tax $5.43 $4.77
Transportation 5.01 5.48
Production tax 1.41 1.18
General and
administrative 3.38 2.71
Total $15.23 $14.14
====== ======
General and administrative costs include $0.69 and
$0.43 for the fourth quarter and full year,
respectively, for non-cash expenses.
-- Overall, production costs are influenced by the commodity mix as oil
production from the Midland Basin increases and natural gas and NGL
production from the Eagle Ford decreases, relative to the total
production mix. LOE costs increase because lifting costs are higher for
oil, and transportation costs decrease because higher cost third party
transportation contracts relate to Eagle Ford natural gas and NGLs. Each
quarter of 2017, LOE costs trended higher partially offset by
transportation costs that trended lower.
-- Fourth quarter of 2017 LOE costs included road work required following
the Texas storms.
NET LOSS AND LOSS PER SHARE
The Company's GAAP net loss for the fourth quarter of 2017 was $26.3 million or $0.24 per diluted common share compared with the fourth quarter of 2016 net loss of $200.9 million, or $2.20 per diluted common share. For the full year 2017, net loss was $160.8 million, or $1.44 per diluted common share, compared with a net loss in 2016 of $757.7 million or $9.90 per diluted common share.
-- The operating margin (before the effects of derivative settlements) per
Boe was up 71% in 2017 compared with 2016, reflecting the portfolio
transition to increased Midland Basin oil production, higher benchmark
prices and a continued focus on controlling costs.
-- The greater net loss in 2016 was predominantly driven by impairment and
abandonment charges in 2016 totaling $435 million and higher depletion,
depreciation and amortization charges.
-- Fourth quarter and full year 2017 net loss includes a one-time tax
benefit of $63.7 million (included in Income tax benefit) related to a
reduction in deferred taxes as a result of the changed corporate income
tax rate under US tax reform.
Net cash provided by operating activities was $144.8 million in the fourth quarter of 2017 and $515.4 million for the full year 2017.
ADJUSTED EBITDAX AND ADJUSTED NET INCOME
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 in the Financial Highlights section at the end of this release.
The Company's adjusted EBITDAX for the fourth quarter of 2017 was $174.0 million, compared with $186.2 million in the prior year period. For the full year 2017, adjusted EBITDAX was $664.7 million, compared with $790.8 million in the prior year.
-- Fourth quarter adjusted EBITDAX included an accrual of $5 million in
other expense that was a non-recurring charge.
The Company's adjusted net loss for the fourth quarter was $8.5 million, or $0.08 per diluted common share, compared with adjusted net loss of $28.7 million, or $0.31 per diluted common share, in the fourth quarter of 2016. For the full year 2017, adjusted net loss was $91.2 million, or $0.82 per diluted common share, compared with adjusted net loss of $142.4 million or $1.86 per diluted common share in 2016.
-- Fourth quarter adjusted net loss removes the one-time tax benefit of
$63.7 million and one-time charge of $5 million, each discussed above,
as well as other items that are non-recurring or difficult to estimate.
FINANCIAL POSITION AND LIQUIDITY
At December 31, 2017, the outstanding principal balance on the Company's long-term debt was $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. The Company's undrawn credit facility plus cash on hand provided $1.2 billion in liquidity at December 31, 2017.
COSTS INCURRED AND TOTAL CAPITAL SPEND
Total capital spend discussed below is a non-GAAP measure and is defined as costs incurred less ARO, capitalized interest and acquisitions. See the Financial Highlights section below for the GAAP reconciliation.
Costs incurred for 2017 were $1,040 million, which included $80.2 million of proved and unproved property acquisitions. Full year 2017 total capital spend was $936 million. Allocated by region, total capital spend was invested 78% in the Permian Basin, 18% in the Eagle Ford, and 4% in the Rocky Mountain region. Allocated by expenditure, total capital spend was invested 88% in development, 5% in infrastructure, 1% in leasehold and 6% in corporate and exploration costs.
-- During 2017, the Company drilled 123 net wells, of which 98 were in the
Permian Basin, 24 were in the Eagle Ford and 1 was in the Powder River
Basin.
-- During 2017, the Company completed 111 net wells, of which 73 were in
the Permian Basin, 35 were in the Eagle Ford and 3 were in the Rocky
Mountain area.
-- During the fourth quarter of 2017, the Company added one rig and one
completions crew to its Midland Basin program.
-- Fourth quarter total capital spend was higher than forecast. A fourth
Permian completions crew was added earlier than originally planned
during the quarter, which enabled the Company to secure an experienced
crew and increase the expected number of flowing completions for the
first quarter of 2018. Total capital spend was also affected by
acceleration of facilities to keep pace with completions. In addition,
drilling and completion costs increased per well as a result of
employing enhanced completion technologies and cost inflation, as cost
escalators tied to oil prices in certain contracts began to take effect.
2018 OPERATING PLAN AND GUIDANCE
The Company's objective is to deliver competitive long-term growth in debt adjusted cash flow. Over the next two years, it is the Company's goal to generate substantial growth in cash flow, end 2019 with net debt:EBITDAX approximating 2.5 times and exit 2019 positioned to deliver continued cash flow growth while keeping total capital spend aligned with cash flow. The Company's two-year strategy to meet these objectives includes:
-- generating substantial growth in high-margin Permian production
-- maintaining the Company's operational excellence and top tier capital
efficiency
-- continuing to demonstrate the value proposition of the RockStar
acquisitions; and
-- managing the balance sheet as measured by ample liquidity, declining net
debt:EBITDAX and absolute debt reduction.
Key assumptions in the Company's 2018 operating plan include:
-- Total capital spend of approximately $1.27 billion.
-- Cost inflation for drilling and completions services per lateral
foot of 10%-15% over average 2017 costs.
-- Permian -- Expect to drill approximately 130 net wells and complete
approximately 100 net wells.
-- Eagle Ford -- Expect to drill approximately 17 net wells and
complete approximately 25 net wells. The Company's JV counterparty
is expected to pay the costs to complete 16 wells, which the Company
expects will effectively fund a significant portion of the Company's
leasehold development obligations in the Eagle Ford. Fewer net
completions for the year are expected to result in lower Eagle Ford
production in 2018 compared to the fourth quarter of 2017 run rate.
-- Total capital spend is weighted to the first half of 2018 as the rig
and completion crew count in the Midland Basin is expected to be
reduced from 9 and 5, respectively, in the first quarter to 7 and 3,
respectively, at year-end.
-- Rocky Mountain -- Nominal capital allocation.
-- Facilities - Approximately $130 million, of which more than one-half
relates to building fresh and produced water infrastructure in the
RockStar area (including associated land costs). This investment is
expected to enable acceleration and control of needed facilities
while significantly reducing future per well capital costs and
operating expenses.
-- Capitalized overhead/exploration - $70-75 million.
-- Average commodity price projections:
-- 2018 WTI oil $57.40 (1Q18 at $64.70 and remainder of 2018 at $55.00
flat), Henry Hub natural gas $3.00, and NGLs 50% of WTI.
-- Asset divestiture timing: The PRB sale is expected to close at the end
of the first quarter, and as a result, production volumes are removed
starting April 2018, but there can be no assurance that this transaction
will close on time or at all.
-- Hedges: Based on the production guidance mid-point, the Company has
hedges in place for approximately 75% of 2018 oil production and 65% of
2018 natural gas production. NGL production is hedged by product and
includes ethane, propane, butanes and natural gasoline.
Full Year 2018 Guidance:
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.
-- Total capital spend: ~$1.27 billion.
-- Production: 42-46 MMBoe, with oil approximately 41% of the commodity
mix.
-- LOE: ~$5.00 per Boe average for the year, reflecting a higher proportion
of oil in the commodity mix. It is expected that 1H18 will exceed the
annual average and 2H18 to be below the annual average, as Permian costs
are expected to be reduced with the planned completion of produced water
handling systems.
-- Transportation: ~$4.50 per Boe average for the year, expected to decline
sequentially through the year as higher cost Eagle Ford production is a
reduced proportion of the commodity mix. It is expected that 1H18 will
exceed the annual average and 2H18 be below the annual average.
-- Production taxes: ~$1.55 per Boe or 4.0-4.5% of pre-hedge revenue.
-- Ad Valorem taxes: $0.55-0.65 per Boe
-- G&A: $125-135 million, including approximately $20 million of non-cash
compensation.
-- Capitalized overhead/exploration: $70-75 million, before dry hole
expense, all of which is included in capital expenditure guidance.
-- DD&A: $13.00-15.00 per Boe.
First quarter of 2018 Guidance:
-- Production of approximately 9.5-10.0 MMBoe, with oil production
approaching 40% of commodity mix.
-- Lower sequential production from the fourth quarter of 2017 is
driven by declines in the Eagle Ford, where no new wells were
completed in the fourth quarter of 2017, and declines in the Rocky
Mountain region.
-- Completion of approximately 18 net wells in the Midland Basin and 5 net
wells in the Eagle Ford during the quarter.
-- Total capital spend of approximately $350 million, which includes
approximately $40 million allocated to facilities and land, which is
largely associated with construction of RockStar fresh and produced
water infrastructure.
OFFICER APPOINTMENT
On February 16, 2018, the Board of Directors of the Company appointed Jennifer Martin Samuels to Vice President - Investor Relations.
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 the Company's website at www.sm-energy.com. Tomorrow morning, the Company will host an associated Q&A session via webcast and conference call. Please join management February 22, 2018 at 8:00 a.m. Mountain Time/10:00 a.m. Eastern Time. 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) or 412-317-0088, and the replay access code is 10116628.
UPCOMING CONFERENCE PARTICIPATION
The Company is not scheduled to participate in any industry conferences during the first quarter of 2018.
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," "pending," "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, full year 2018 guidance, first quarter of 2018 guidance, expectations concerning the planned closing of a previously announced divestiture, expectations about future cost inflation, 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 uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions (including any delay in the Company's pending Powder River Basin asset divestiture as a result of litigation); 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 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 2017 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
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
For the Three Months Ended For the Twelve Months Ended
December 31, December 31,
Production Data: 2017 2016 Percent 2017 2016 Percent
Change Change
--- ------
Average realized sales price, before
the effects of derivative
settlements:
Oil (per Bbl) $53.32 $43.58 22% $47.88 $36.85 30%
Gas (per Mcf) $3.09 $2.86 8% $3.00 $2.30 30%
NGL (per Bbl) $26.01 $20.02 30% $22.35 $16.16 38%
--- ---
Equivalent (per BOE) $32.95 $25.86 27% $28.20 $21.32 32%
Average realized sales price,
including the effects of derivative
settlements:
Oil (per Bbl) $48.90 $48.96 - % $45.60 $51.48 (11)%
Gas (per Mcf) $4.03 $3.21 26% $3.72 $2.94 27%
NGL (per Bbl) $18.84 $16.92 11% $18.91 $15.56 22%
--- ---
Equivalent (BOE) $32.16 $27.59 17% $28.68 $27.28 5%
Production:
Oil (MMBbls) 3.8 4.0 (5)% 13.7 16.6 (18)
%
Gas (Bcf) 26.0 35.2 (26)% 123.0 146.9 (16)
%
NGL (MMBbls) 2.2 3.5 (37)% 10.3 14.2 (27)%
--- ---
MMBOE (6:1) 10.4 13.4 (23)% 44.5 55.3 (20)%
Average daily production:
Oil (MBbls/d) 41.5 43.9 (5)% 37.4 45.4 (17)%
Gas (MMcf/d) 282.5 382.7 (26)% 337.0 401.5 (16)%
NGL (MBbls/d) 24.0 37.9 (37)% 28.2 38.8 (27)%
--- ---
MBOE/d (6:1) 112.6 145.6 (23)% 121.8 151.0 (19)%
Per BOE Data:
Realized price before
the effects of
derivative
settlements $32.95 $25.86 27% $28.20 $21.32 32%
Lease operating
expense 5.10 3.67 39% 4.43 3.51 26%
Transportation costs 5.01 6.39 (22)% 5.48 6.16 (11)%
Production taxes 1.41 1.11 27% 1.18 0.94 26%
Ad valorem tax expense 0.33 0.17 94% 0.34 0.21 62%
General and
administrative 3.38 2.49 36% 2.71 2.29 18%
---- ---- --- ---- ---- ---
Operating profit,
before the effects of
derivative
settlements $17.72 $12.03 47% $14.06 $8.21 71%
Derivative settlement
gain (loss) (0.79) 1.73 (146)% 0.48 5.96 (92)%
----- ---- ----- ---- ---- ----
Operating profit,
including the effects
of derivative
settlements $16.93 $13.76 23% $14.54 $14.17 3%
====== ====== === ====== ====== ===
Depletion,
depreciation,
amortization, and
asset retirement
obligation liability
accretion $12.69 $12.81 (1)% $12.53 $14.30 (12)%
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Balance Sheets
---------------------------
(in thousands, except share
data) December 31, December 31,
ASSETS 2017 2016
---- ----
Current assets:
Cash and cash equivalents $313,943 $9,372
Accounts receivable 160,154 151,950
Derivative assets 64,266 54,521
Prepaid expenses and other 10,752 8,799
------ -----
Total current assets 549,115 224,642
------- -------
Property and equipment (successful efforts
method):
Proved oil and gas properties 6,139,379 5,700,418
Less -accumulated depletion,
depreciation, and amortization (3,171,575) (2,836,532)
Unproved oil and gas properties 2,047,203 2,471,947
Wells in progress 321,347 235,147
Oil and gas properties held for
sale, net 111,700 372,621
Other property and equipment,
net of accumulated
depreciation of $49,985 and
$42,882, respectively 106,738 137,753
------- -------
Total property and equipment,
net 5,554,792 6,081,354
--------- ---------
Noncurrent assets:
Derivative assets 40,362 67,575
Other noncurrent assets 32,507 19,940
------ ------
Total other noncurrent assets 72,869 87,515
------ ------
Total assets $6,176,776 $6,393,511
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
expenses $386,630 $299,708
Derivative liabilities 172,582 115,464
Total current liabilities 559,212 415,172
------- -------
Noncurrent liabilities:
Revolving credit facility - -
Senior Notes, net of
unamortized deferred financing
costs 2,769,663 2,766,719
Senior Convertible Notes, net
of unamortized discount and
deferred financing costs 139,107 130,856
Asset retirement obligations 103,026 96,134
Asset retirement obligations
associated with oil and gas
properties held for sale 11,369 26,241
Deferred income taxes 79,989 315,672
Derivative liabilities 71,402 98,340
Other noncurrent liabilities 48,400 47,244
------ ------
Total noncurrent liabilities 3,222,956 3,481,206
--------- ---------
Stockholders' equity:
Common stock, $0.01 par value -
authorized: 200,000,000
shares; issued and
outstanding: 111,687,016 and
111,257,500 shares,
respectively 1,117 1,113
Additional paid-in capital 1,741,623 1,716,556
Retained earnings 665,657 794,020
Accumulated other comprehensive
loss (13,789) (14,556)
Total stockholders' equity 2,394,608 2,497,133
--------- ---------
Total liabilities and
stockholders' equity $6,176,776 $6,393,511
========== ==========
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Operations
-------------------------------------
(in thousands, except per
share data) For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
2017 2016 2017 2016
---- ---- ---- ----
Operating revenues and other income:
Oil, gas, and NGL production
revenue $341,187 $346,296 $1,253,783 $1,178,426
Net gain (loss) on
divestiture activity 537 33,661 (131,028) 37,074
Other operating revenues, net (1,186) (57) 6,621 1,950
------ --- ----- -----
Total operating revenues and
other income 340,538 379,900 1,129,376 1,217,450
------- ------- --------- ---------
Operating expenses:
Oil, gas, and NGL production
expense 122,833 151,907 507,906 597,565
Depletion, depreciation,
amortization, and asset
retirement obligation
liability accretion 131,393 171,552 557,036 790,745
Exploration(1) 16,886 23,699 56,179 65,641
Impairment of proved
properties - 76,780 3,806 354,614
Abandonment and impairment of
unproved properties 12,115 74,450 12,272 80,367
General and administrative
(including stock-based
compensation)(1) 35,021 33,311 120,585 126,428
Net derivative loss(2) 115,778 129,547 26,414 250,633
Other operating expenses 7,364 3,041 13,667 10,772
----- ----- ------ ------
Total operating expenses 441,390 664,287 1,297,865 2,276,765
------- ------- --------- ---------
Loss from operations (100,852) (284,387) (168,489) (1,059,315)
Non-operating income (expense):
Interest expense (43,618) (46,356) (179,257) (158,685)
Gain (loss) on extinguishment
of debt - - (35) 15,722
Other, net 1,067 130 3,968 362
----- --- ----- ---
Loss before income taxes (143,403) (330,613) (343,813) (1,201,916)
Income tax benefit 117,145 129,667 182,970 444,172
------- ------- ------- -------
Net loss $(26,258) $(200,946) $(160,843) $(757,744)
======== ========= ========= =========
Basic weighted-average
common shares outstanding 111,611 91,440 111,428 76,568
======= ====== ======= ======
Diluted weighted-average
common shares outstanding 111,611 91,440 111,428 76,568
======= ====== ======= ======
Basic net loss per common
share $(0.24) $(2.20) $(1.44) $(9.90)
====== ====== ====== ======
Diluted net loss per common
share $(0.24) $(2.20) $(1.44) $(9.90)
====== ====== ====== ======
(1) Non-cash stock-based compensation component
included in:
Exploration expense $2,402 $1,410 $6,300 $6,447
General and administrative
expense $5,021 $5,002 $17,283 $20,450
(2) The net derivative loss line item consists of the
following:
Settlement (gain) loss $8,168 $(23,244) $(21,234) $(329,478)
Loss on fair value changes 107,610 152,791 47,648 580,111
Net derivative loss $115,778 $129,547 $26,414 $250,633
======== ======== ======= ========
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Stockholders' Equity
-------------------------------------
(in thousands, except share data and dividends per
share) Additional Accumulated Total
Paid-in Other Stockholders'
Capital Comprehensive Equity
Loss
----
Common Stock Retained
Earnings
--------
Shares Amount
------ ------
Balances, January 1,
2015 67,463,060 $675 $283,295 $2,013,997 $(11,312) $2,286,655
Net loss - - - (447,710) - (447,710)
Other comprehensive
loss - - - - (2,090) (2,090)
Cash dividends, $ 0.10
per share - - - (6,772) - (6,772)
Issuance of common
stock under Employee
Stock Purchase Plan 197,214 2 4,842 - - 4,844
Issuance of common
stock upon vesting of
RSUs and settlement
of PSUs, net of
shares used for tax
withholdings 375,523 4 (8,682) - - (8,678)
Stock-based
compensation expense 39,903 - 27,467 - - 27,467
Other - - (1,315) - - (1,315)
--- --- ------ --- --- ------
Balances, December 31,
2015 68,075,700 $681 $305,607 $1,559,515 $(13,402) $1,852,401
Net loss - - - (757,744) - (757,744)
Other comprehensive
loss - - - - (1,154) (1,154)
Cash dividends, $ 0.10
per share - - - (7,751) - (7,751)
Issuance of common
stock under Employee
Stock Purchase Plan 218,135 2 4,196 - - 4,198
Issuance of common
stock upon vesting of
RSUs and settlement
of PSUs, net of
shares used for tax
withholdings 199,243 2 (2,356) - - (2,354)
Stock-based
compensation expense 53,473 1 26,896 - - 26,897
Issuance of common
stock from stock
offerings, net of tax 42,710,949 427 1,382,666 - - 1,383,093
Equity component of
1.50% Senior
Convertible Notes due
2021 issuance, net of
tax - - 33,575 - - 33,575
Purchase of capped
call transactions - - (24,195) - - (24,195)
Other - - (9,833) - - (9,833)
--- --- ------ --- --- ------
Balances, December 31,
2016 111,257,500 $1,113 $1,716,556 $794,020 $(14,556) $2,497,133
Net loss - - - (160,843) - (160,843)
Other comprehensive
income - - - - 767 767
Cash dividends, $0.10
per share - - - (11,144) - (11,144)
Issuance of common
stock under Employee
Stock Purchase Plan 186,665 2 2,621 - - 2,623
Issuance of common
stock upon vesting of
RSUs, net of shares
used for tax
withholdings 171,278 1 (1,241) - - (1,240)
Stock-based
compensation expense 71,573 1 22,699 - - 22,700
Cumulative effect of
accounting change - - 1,108 43,624 - 44,732
Other - - (120) - - (120)
--- ----
Balances, December 31,
2017 111,687,016 $1,117 $1,741,623 $665,657 $(13,789) $2,394,608
=========== ====== ========== ======== ======== ==========
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Consolidated Statements of Cash
Flows
-------------------------------
(in thousands) For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
2017 2016 2017 2016
---- ---- ---- ----
(as adjusted) (as adjusted)
Cash flows from operating activities:
Net loss $(26,258) $(200,946) $(160,843) $(757,744)
Adjustments to reconcile net loss to net
cash provided by operating activities:
Net (gain) loss on
divestiture activity (537) (33,661) 131,028 (37,074)
Depletion, depreciation,
amortization, and asset
retirement obligation
liability accretion 131,393 171,552 557,036 790,745
Exploratory dry hole
expense 2,381 - 2,381 (16)
Impairment of proved
properties - 76,780 3,806 354,614
Abandonment and
impairment of unproved
properties 12,115 74,450 12,272 80,367
Impairment of other
property and equipment - - - -
Stock-based
compensation expense 6,540 6,412 22,700 26,897
Net derivative loss 115,778 129,547 26,414 250,633
Derivative settlement
gain (loss) (8,168) 23,244 21,234 329,478
Amortization of debt
discount and deferred
financing costs 3,798 4,251 16,276 9,938
(Gain) loss on
extinguishment of debt - - 35 (15,722)
Deferred income taxes (124,608) (133,873) (192,066) (448,643)
Plugging and abandonment (640) (992) (2,735) (6,214)
Other, net 3,526 5,140 8,239 (3,701)
Changes in current assets and
liabilities:
Accounts receivable (7,505) (11,783) 13,997 (10,562)
Prepaid expenses and
other 7,002 826 (1,953) 8,478
Accounts payable and
accrued expenses 23,425 11,956 44,985 (53,210)
Accrued derivative
settlements 6,538 14,889 12,584 34,540
Net cash provided by
operating activities 144,780 137,792 515,390 552,804
------- ------- ------- -------
Cash flows from investing activities:
Net proceeds from the
sale of oil and gas
properties (1,646) 744,233 776,719 946,062
Capital expenditures (263,384) (137,117) (888,353) (629,911)
Acquisition of proved
and unproved oil and
gas properties (2,507) (2,161,937) (89,896) (2,183,790)
Net cash used in
investing activities (267,537) (1,554,821) (201,530) (1,867,639)
-------- ---------- -------- ----------
Cash flows from financing activities:
Proceeds from credit
facility - 204,000 406,000 947,000
Repayment of credit
facility - (204,000) (406,000) (1,149,000)
Debt issuance costs
related to credit
facility - - - (3,132)
Net proceeds from Senior
Notes - (757) - 491,640
Cash paid to repurchase
Senior Notes - - (2,344) (29,904)
Cash paid for
extinguishment of debt - - (13) -
Net proceeds from Senior
Convertible Notes - (64) - 166,617
Cash paid for capped
call transactions - (86) - (24,195)
Net proceeds from sale
of common stock 885 405,002 2,623 938,268
Dividends paid (5,581) (4,347) (11,144) (7,751)
Net share settlement
from issuance of stock
awards (1) (13) (1,240) (2,354)
Other, net (18) - (171) -
Net cash provided by
(used in) financing
activities (4,715) 399,735 (12,289) 1,327,189
------ ------- ------- ---------
Net change in cash, cash
equivalents, and
restricted cash (127,472) (1,017,294) 301,571 12,354
Cash, cash equivalents,
and restricted cash at
beginning of period 441,415 1,029,666 12,372 18
Cash, cash equivalents,
and restricted cash at
end of period $313,943 $12,372 $313,943 $12,372
======== ======= ======== =======
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 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 For the Twelve Months
Ended December 31, Ended December 31,
2017 2016 2017 2016
Net loss (GAAP) $(26,258) $(200,946) $(160,843) $(757,744)
Interest expense 43,618 46,356 179,257 158,685
Interest income (1,067) (130) (3,968) (362)
Income tax benefit (117,145) (129,667) (182,970) (444,172)
Depletion, depreciation,
amortization, and asset
retirement obligation
liability accretion 131,393 171,552 557,036 790,745
Exploration (2) 14,484 22,289 49,879 59,194
Impairment of proved
properties - 76,780 3,806 354,614
Abandonment and
impairment of unproved
properties 12,115 74,450 12,272 80,367
Stock-based
compensation expense 6,540 6,412 22,700 26,897
Net derivative loss 115,778 129,547 26,414 250,633
Derivative settlement
gain (loss) (8,168) 23,244 21,234 329,478
Net (gain) loss on
divestiture activity (537) (33,661) 131,028 (37,074)
(Gain) loss on
extinguishment of debt - - 35 (15,722)
Other, net 3,200 (7) 8,820 (4,764)
Adjusted EBITDAX (Non-
GAAP) $173,953 $186,219 $664,700 $790,775
-------- -------- -------- --------
Interest expense (43,618) (46,356) (179,257) (158,685)
Interest income 1,067 130 3,968 362
Income tax benefit 117,145 129,667 182,970 444,172
Exploration (2) (14,484) (22,289) (49,879) (59,194)
Exploratory dry hole
expense 2,381 - 2,381 (16)
Amortization of debt
discount and deferred
financing costs 3,798 4,251 16,276 9,938
Deferred income taxes (124,608) (133,873) (192,066) (448,643)
Plugging and abandonment (640) (992) (2,735) (6,214)
Other, net 326 5,147 (581) 1,063
Changes in current
assets and liabilities 29,460 15,888 69,613 (20,754)
------
Net cash provided by
operating activities
(GAAP) $144,780 $137,792 $515,390 $552,804
======== ======== ======== ========
(1) Adjusted EBITDAX represents net income
(loss) before interest expense, interest
income, 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
accompanying statements of operations for
the component of stock-based
compensation expense recorded to
exploration expense.
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
Adjusted Net Loss For the Three Months For the Twelve Months
Ended December 31, Ended December 31,
(in thousands, except per share data)
2017 2016 2017 2016
---- ---- ---- ----
Net loss (GAAP) $(26,258) $(200,946) $(160,843) $(757,744)
Net derivative loss 115,778 129,547 26,414 250,633
Derivative settlement gain (loss) (8,168) 23,244 21,234 329,478
Net (gain) loss on divestiture activity (537) (33,661) 131,028 (37,074)
Impairment of proved properties - 76,780 3,806 354,614
Abandonment and impairment of unproved
properties 12,115 74,450 12,272 80,367
Termination fee on temporary second
lien facility - - - 10,000
(Gain) loss on extinguishment of debt - - 35 (15,722)
Other, net(1) 8,200 (306) 13,820 (7,731)
Tax effect of adjustments(2) (45,987) (97,760) (75,308) (349,173)
US tax reform(3) (63,675) - (63,675) -
Adjusted net loss (Non-GAAP)(4) $(8,532) $(28,652) $(91,217) $(142,352)
===
Diluted net loss per common share
(GAAP) $(0.24) $(2.20) $(1.44) $(9.90)
Net derivative loss 1.04 1.42 0.24 3.27
Derivative settlement gain (loss) (0.07) 0.25 0.19 4.30
Net gain (loss) on divestiture activity - (0.37) 1.18 (0.48)
Impairment of proved properties - 0.84 0.03 4.63
Abandonment and impairment of unproved
properties 0.11 0.81 0.11 1.05
Termination fee on temporary second
lien facility - - - 0.13
(Gain) loss on extinguishment of debt - - - (0.21)
Other, net(1) 0.07 (0.01) 0.12 (0.10)
Tax effect of adjustments(2) (0.42) (1.05) (0.68) (4.55)
US tax reform(3) (0.57) - (0.57) -
Adjusted net loss per diluted common
share (Non-GAAP)(4) $(0.08) $(0.31) $(0.82) $(1.86)
===
Diluted weighted-average shares
outstanding (GAAP) 111,611 91,440 111,428 76,568
(1) For the three-month and twelve-month periods ended December 31, 2017, the adjustment is related to
impairment on materials inventory, pension settlement expense, the change in Net Profits Plan liability,
bad debt expense, and an accrual for a non-recurring matter. For the three-month and twelve-month
periods ended December 31, 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. Pension settlement expense is included within exploration expenses and general and
administrative expense on the Company's consolidated statements of operations. Other noted items are
included in other operating expenses on the Company's consolidated statements of operations.
(2) For the three and twelve-month periods ended December 31, 2017, adjustments are shown before tax
effect which is calculated using a tax rate of 36.1%, which approximates the Company's statutory tax
rate adjusted for ordinary permanent differences. For the three and twelve-month periods ended
December 31, 2016, adjustments are shown before tax effect and are calculated using a tax rate of 36.2%,
which approximates the Company's statutory tax rate adjusted for ordinary permanent differences.
(3) US tax reform adjustment primarily relates to the enactment of the 2017 Tax Act on December 22, 2017,
which reduced the Company's federal tax rate for 2018 and future years from 35 percent to 21 percent.
(4) 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.
Regional proved oil and gas reserve quantities:
-----------------------------------------------
Permian Eagle Ford(1) Rocky Total
Mountain
--------
Year-end 2017 proved reserves
Oil (MMBbl) 117.5 13.3 27.4 158.2
Gas (Bcf) 252.8 998.1 29.2 1,280.1
NGL (MMBbl) 0.2 95.6 0.7 96.5
----
Total (MMBOE) 159.9 275.2 33.0 468.1
% Proved developed 34% 52% 53% 46%
Note: Totals may not sum
due to rounding
(1) Includes nominal
amounts outside of the
Eagle Ford.
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 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 Year Ended
December 31, 2017
-----------------
Costs incurred in oil and gas activities
(GAAP): $1,040.0
Asset retirement obligations (12.1)
Capitalized interest (12.6)
Proved property acquisitions(2) (1.6)
Unproved property acquisitions (78.6)
Other 1.3
Total capital spend (Non-GAAP): $936.4
======
(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 $1.4 million of
ARO associated with proved property
acquisitions for the year ended December
31, 2017.
(3) The Company completed several
primarily non-monetary acreage trades in
the Midland Basin during 2017 totaling
$294.0 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.
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2017
PV-10 Reconciliation:
---------------------
(in millions)
Reconciliation of
standardized measure
(GAAP) to PV-10
(Non-GAAP)(1) As of
December 31, 2017
-----------------
Standardized measure
of discounted future
net cash flows
(GAAP): $3,024.1
Add: 10 percent annual
discount, net of
income taxes 2,573.2
Add: future
undiscounted income
taxes 205.7
-----
Undiscounted future
net cash flows 5,803.0
Less: 10 percent
annual discount
without tax effect (2,746.5)
PV-10 (Non-GAAP): $3,056.5
========
(1) The non-GAAP measure of PV-10 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 PV-10 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. PV-10 should not be considered in isolation or as a
substitute for other measures prepared under GAAP.
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SOURCE SM Energy Company
