SM Energy Reports 2017 Results And 2018 Operating Plan: Permian Execution Outstanding, Cash Flow Gro

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 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:

By region:

 

• 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:

 

• 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:

 

• 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, [email protected], 303-864-2507