Attached files
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| 8-K - 8-K - SM Energy Co | form8-k102815.htm |
EXHIBIT 99.1
FOR IMMEDIATE RELEASE
SM ENERGY REPORTS THIRD QUARTER OF 2015 RESULTS -
EXCEEDING EXPECTATIONS FOR 2015 THROUGH EFFICIENCIES AND PERFORMANCE
• | Produced 16.1 million barrels of oil equivalent (MMBOE), up 22% from the prior year period and above plan |
• | Realized $259.4 million adjusted EBITDAX (see GAAP reconciliations below), exceeding the Company's expectations |
• | Maintained modest debt to adjusted TTM EBITDAX at 1.9 times |
• | Monitored 130 days of success with Eagle Ford Pilot Test #1, which supports downspacing in Eagle Ford East |
• | Achieving substantial progress in well performance and cost efficiencies |
DENVER, CO October 27, 2015 - SM Energy Company (NYSE: SM) announces its financial results for the third quarter of 2015 and provides an operations update. In conjunction with this release, the Company posted an investor presentation with additional third quarter earnings and operations detail to the Company's website at www.sm-energy.com. This presentation will be referenced during the conference call scheduled for 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on October 28, 2015. Information for the call can be found below.
MANAGEMENT COMMENTARY
Comments from President and Chief Executive Officer Jay Ottoson: "I am pleased to report another excellent quarter with production and EBITDAX that exceeded our internal forecasts. Third quarter production was up sequentially from the second quarter (adjusted for assets sold in the second quarter) and up 22% compared with the third quarter last year.
"Operational execution continues to drive our outperformance. We are working hard to reduce costs and apply technology effectively on a number of fronts. We are reducing drilling times, optimizing completions and generating better well results in our core development programs. For example, drilling and completion costs for our operated Eagle Ford wells in the third quarter were down nearly 50% from our 2014 average. At the same time, we have been conducting several pilot tests in high productivity areas of the Eagle Ford and Bakken/Three Forks intended to prove up additional economic drilling inventory. Test results to date have been positive and have translated into higher than forecast production.
"Looking into 2016, we plan to focus our activity on our programs that generate the best returns. Our diligent efforts to reduce costs and improve well performance will continue, and we expect to allocate an increased portion of capital to the Permian and Williston Basins. Fundamental to the 2016 operating plan will be aligning capital spending with estimated EBITDAX to optimize cash flow and inventory expansion, resulting in differential value creation in 2016."
THIRD QUARTER 2015 RESULTS
Production for the third quarter of 2015 was 16.1 MMBOE, or 174.5 MBOE/d, up 22% compared with 13.1 MMBOE, or 142.5 MBOE/d, in the third quarter of 2014. Total production increased sequentially, adjusted for second quarter assets sales, and exceeded the Company's expectations by approximately 0.6 MMBOE, despite an 11% sequential decline in non-operated Eagle Ford production.
Strong production was driven by well performance in the Company's core areas that continues to exceed the Company's year-end 2014 type curves plus a number of positive test wells in the Eagle Ford that came on sales during the quarter. Specifically, Eagle Ford Test #1 reached a peak natural gas rate of 105 MMcf/d during the quarter and Test #3 is on sales with several wells producing more than 10 MMcf/d each, while still cleaning up. Of note, these tests were drilled in high natural gas content areas, increasing the mix of natural gas in total third quarter production. The production mix for the quarter was 28% oil, 45% natural gas and 27% natural gas liquids ("NGLs"). For the first nine months of 2015, total production was 49.3 MMBOE, up 27% compared with 39.0 MMBOE in the first nine months of 2014.
Sequential Production
Production | 3Q15 | 2Q15* | |||
Oil Production (MMBbls) | 4.5 | 5.1 | |||
Gas Production (Bcf) | 43.3 | 40.3 | |||
NGL Production (MMBbls) | 4.3 | 4.0 | |||
Total Production (MMBOE) | 16.1 | 15.8 | |||
Equivalent Daily Production (MBOE/d) | 174.5 | 173.6 | |||
*2Q15 production adjusted for asset sales completed during that quarter.
Pricing in the third quarter of 2015 reflected a 52% decline in WTI oil prices, a 30% decline in NYMEX natural gas prices and a 54% decline in OPIS NGL prices from the prior year period. The Company had approximately 48% of oil production, 34% of natural gas production and 40% of NGL production hedged during the quarter. The table below provides the average realized prices received by product, as well as the adjusted prices received after taking into account settlements for derivative transactions:
Average Realized Commodity Prices for the Three Months Ended September 30, 2015
Before the effect of derivative settlements | After the effect of derivative settlements | ||
Oil ($/Bbl) | $40.03 | $60.05 | |
Gas ($/Mcf) | $2.77 | $3.22 | |
Natural gas liquids ($/Bbl) | $15.18 | $16.12 | |
Equivalent ($/BOE) | $22.84 | $29.92 | |
Operating costs in the third quarter of 2015 included lease operating expenses of $3.86 per BOE, down $0.72 per BOE from the prior year period, and transportation expenses of $6.27 per BOE, up $0.05 per BOE from the prior year period. Lease operating expenses on the Company’s operated properties tracked internal forecasts and included planned higher workover expenses compared with the second quarter of 2015. Third quarter lease operating expenses at the Company’s non-operated Eagle Ford properties increased Company-wide lease operating
expenses $0.20 per BOE sequentially. For the first nine months of 2015, lease operating expenses averaged $3.70 per BOE and transportation costs averaged $5.99 per BOE, down 13% and 4%, respectively.
General and administrative expenses for the third quarter of 2015 were $37.8 million, or $2.35 per BOE. Net of non-cash compensation expenses of $5.4 million, general and administrative expenses were $32.4 million, or $2.02 per BOE. General and administrative expenses per BOE were down significantly compared with the prior year periods, down 26% in the third quarter and down 15% in the first nine months.
Net income for the third quarter of 2015 was $3.1 million, or $0.05 per diluted common share, compared with net income of $208.9 million, or $3.05 per diluted common share, in the third quarter of 2014. For the first nine months of 2015, the Company's net loss was $107.5 million, or $1.59 per diluted common share, compared with net income of $334.3 million, or $4.90 per diluted common share, in the prior year period.
Adjusted net loss for the third quarter of 2015 was $23.3 million, or $0.34 per diluted common share, compared with adjusted net income of $98.6 million, or $1.44 per diluted common share, in the third quarter of 2014. Lower adjusted net income is predominantly due to the 51% decline in average prices received per BOE, partially offset by the 22% increase in production and 15% decrease in production costs per BOE. Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and are generally items whose timing and/or amount cannot be reasonably estimated.
Adjusted earnings before interest, taxes, depletion, amortization and accretion, and exploration expense, or adjusted EBITDAX, was $259.4 million for the third quarter of 2015, compared with $406.2 million in the third quarter of 2014. Lower adjusted EBITDAX is primarily a result of significantly lower commodity prices in the third quarter of 2015, partially offset by higher production and lower costs per BOE, as discussed above.
Adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the Financial Highlights section at the end of this release for additional information about these measures.
CAPITAL, OPERATIONS AND GUIDANCE
Capital Expenditures
The Company’s total 2015 capital expenditures are estimated at approximately $1.28 billion. Capital expenditures through the first nine months totaled approximately $1.1 billion.
The Company's 2015 drilling program is primarily focused on its Eagle Ford shale and Bakken/Three Forks plays. Third quarter of 2015 capital expenditures were $277 million, down approximately 18% from the second quarter of 2015, as the Company reduced its drilling activity from nine rigs at the end of the second quarter to seven rigs currently. The Company's seven active operated rigs include four in the Eagle Ford, two in the Bakken/Three Forks and one in the Powder River Basin. At year-end, the Company anticipates releasing one rig from its Eagle Ford program and adding one rig in the Permian Basin. The Company is currently deferring most completions in both its Eagle Ford and Bakken/Three Forks programs and plans to increase completion activity around year-end.
Eagle Ford
Third quarter of 2015 net production averaged 134.5 BOE/d, including both operated and non-operated wells. Daily production increased 31% from the third quarter of 2014 and increased 3% sequentially from the second quarter of 2015, despite an 11% sequential decline in non-operated production from the area.
The focus on operational execution in the operated Eagle Ford is resulting in a number of quantifiable results. For example, comparison of third quarter of 2015 data with 2014 full year averages shows a 54% decline in completion costs per lateral foot and a 28% reduction in drilling costs per lateral foot. The average days from spud-to-rig per 1000 feet of total measured depth improved approximately 14% in the program.
The Company has scheduled nine Eagle Ford multi-well pilot tests intended to test the potential for inventory expansion across its acreage position through downspacing, infill drilling and the addition of the Upper Eagle Ford interval. Wells have been drilled and completed in five of the nine tests, with the remaining tests expected to be completed in 2016. To date, Eagle Ford test results are encouraging. On Test #1, a 14-well test of downspacing to 450 feet, the Company has approximately 130 days of sales. This successful test to date provides the Company with confidence that future drilling programs in the East Area can support 450 foot well-spacing. Test #3, a 5-well test of the Upper and Lower Eagle Ford intervals, includes 312 foot plan-view spacing. While this test is in a dry natural gas area, its broader implications are important as to date it appears to extend the footprint of the Company's Upper Eagle Ford to the south and support the potential for higher density plan-view spacing throughout the Company's 250-350 foot thick Eagle Ford shale position. Tests #2 through #5 are completed and either on flowback or have too few days of production to report.
Bakken/Three Forks
Third quarter of 2015 production from the Company's Bakken/Three Forks program averaged 22.2 MBOE/d and was 85% oil. Production increased 27% from the third quarter of 2014 and decreased 7% sequentially, as the Company continues to actively drill in the area but not complete all wells drilled. As of the end of the third quarter of 2015, the Company had an inventory of 47 gross and 39 net operated wells drilled and uncompleted in the area.
The Company's operations have focused on drilling and completion efficiencies. Drilling days in 2015 are down 11% on average from 2014 and the Company recently drilled a Divide County Bakken well, spud to rig release, in 10 days. Enhanced completions are driving 20%-30% increased recoveries per well as the Company employs plug-and-perf/cemented liner completions. Overall, costs in the area have been reduced by 20%-25% per well compared with similar wells in 2014.
Cumulative production from nine wells in Divide County, North Dakota testing the Bakken interval continues to perform above the Company's type curve expectations for the Three Forks interval, demonstrating the economic viability of Bakken locations in the area. Two additional Bakken wells were recently completed farther south on the Company's acreage, which could expand the potential of the Bakken interval to the south. The addition of the Bakken interval has the potential to significantly increase the Company's proved reserves and the inventory of drilling locations in Divide County.
Guidance
The Company has slightly modified full year 2015 guidance to narrow certain ranges. In addition, the Company has slightly increased the mid-point of production guidance and has slightly lowered the mid-point of transportation and ad valorem tax cost guidance. The following table presents updated production and performance guidance for full year 2015:
Revised Guidance for 2015 | |
FY2015 | |
Production (MMBOE) | 63.6 - 64.4 |
Average daily production (MBOE/d) | 174 - 176 |
LOE ($/BOE) | $3.70 - $3.90 |
Ad Valorem ($/BOE) | $0.45 - $0.50 |
Transportation ($/BOE) | $6.10 - $6.25 |
Production taxes (% of pre-derivative oil, gas, and NGL revenue) | 4.5% - 5.0% |
G&A - Cash ($/BOE) | $2.40 - $2.70 |
G&A - Non-cash ($/BOE) | $0.30 - $0.40 |
Total G&A ($/BOE) | $2.70 - $3.10 |
DD&A ($/BOE) | $13.75 - $14.25 |
Effective income tax rate range | 39.6% - 40.6% |
FINANCIAL POSITION AND LIQUIDITY
The Company ended the third quarter of 2015 with long-term debt of $2.53 billion, including $2.35 billion in senior notes and $0.18 billion drawn on its revolving credit facility. As previously reported, under the Company’s credit facility, the borrowing base is $2.0 billion and aggregate commitments are $1.5 billion, providing the Company with ample liquidity.
The Company has commodity derivative contracts in place for the fourth quarter of 2015 representing approximately 43% of oil, 45% of natural gas and 48% of NGL forecast volumes at the midpoint, and for 2016 representing approximately 30% of oil, 50% of natural gas and 50% of NGL, assuming 2015 exit rate production. A summary of commodity derivative contracts through 2016 are as follows:
Derivative Position through 2016 | |||||||||
as of October 21, 2015* | |||||||||
Oil | Gas | NGL*** | |||||||
Period | Volume (MBbls) | Weighted Avg. Price** ($/Bbl) | Volume (BBTU) | Weighted Avg. Price** ($/MMBTU) | Volume (MBbls) | Weighted Avg. Price - Mont Belvieu ($/Bbl) | |||
4Q15 | 2,006 | $87.92 | 17,656 | $4.07 | 1,709 | $21.58 | |||
1Q16 | 1,868 | $86.93 | 23,341 | $3.90 | 2,250 | $15.67 | |||
2Q16 | 1,752 | $86.73 | 20,780 | $3.39 | 2,018 | $15.71 | |||
3Q16 | 1,170 | $90.29 | 18,829 | $3.33 | 1,613 | $14.22 | |||
4Q16 | 780 | $90.05 | 17,236 | $3.83 | 1,280 | $13.32 | |||
* Includes all commodity derivative contracts for settlement at any time during the fourth quarter of 2015 and later periods, entered into as of 10/21/15. | |||||||||
** Weighted average prices are shown as NYMEX equivalents. For collars, floor prices were used to calculate the weighted average price. | |||||||||
***NGL derivative positions include: 4Q15-2Q16 propane, ethane and butanes only; 3Q16-4Q16 propane and ethane only. | |||||||||
EARNINGS CALL INFORMATION
The Company has scheduled a webcast and conference call to discuss third quarter 2015 financial and operational results. The webcast is scheduled for October 28, 2015, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). The webcast can be accessed from the Company's website at www.sm-energy.com, and will remain available for replay for approximately 30 days. You may also join via teleconference at the dial-in information below. A telephonic replay of the call will be available approximately two hours after the call through November 11, 2015.
Call Type | Phone Number | Conference ID | ||
Domestic Participant | 877-303-1292 | 57682556 | ||
Domestic Replay | 855-859-2056 | 57682556 | ||
International Participant | 315-625-3086 | 57682556 | ||
International Replay | 404-537-3406 | 57682556 | ||
INFORMATION ABOUT FORWARD LOOKING STATEMENTS
This release contains forward looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward-looking statements. These risks include factors such as the availability, proximity and capacity of gathering, processing and transportation facilities; the volatility and level of oil, natural gas, and natural gas liquids prices, including any impact on the Company’s asset carrying values or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities, costs or results, including from pilot tests; the uncertainty of negotiations to
result in an agreement or a completed transaction; the uncertain nature of divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected divestiture, joint venture, farm down or similar efforts; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors” section of SM Energy's 2014 Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. The forward-looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by securities laws.
ABOUT THE COMPANY
SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids in onshore North America. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at
www.sm-energy.com.
SM ENERGY CONTACTS:
INVESTORS:
Jennifer Martin Samuels, jsamuels@sm-energy.com, 303-864-2507
MEDIA:
Patty Errico, perrico@sm-energy.com, 303-830-5052
SM ENERGY COMPANY | ||||||||||||||||||||
FINANCIAL HIGHLIGHTS (unaudited) | ||||||||||||||||||||
September 30, 2015 | ||||||||||||||||||||
Production Data | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||
2015 | 2014 | Percent Change | 2015 | 2014 | Percent Change | |||||||||||||||
Average realized sales price, before the effects of | ||||||||||||||||||||
derivative settlements: | ||||||||||||||||||||
Oil (per Bbl) | $ | 40.03 | $ | 86.56 | (54)% | $ | 43.43 | $ | 89.08 | (51)% | ||||||||||
Gas (per Mcf) | 2.77 | 4.49 | (38)% | 2.69 | 4.86 | (45)% | ||||||||||||||
NGL (per Bbl) | 15.18 | 34.86 | (56)% | 16.20 | 36.34 | (55)% | ||||||||||||||
Equivalent (per BOE) | $ | 22.84 | $ | 47.06 | (51)% | $ | 24.36 | $ | 48.63 | (50)% | ||||||||||
Average realized sales price, including the effects of | ||||||||||||||||||||
derivative settlements: | ||||||||||||||||||||
Oil (per Bbl) | $ | 60.05 | $ | 86.44 | (31)% | $ | 61.67 | $ | 86.71 | (29)% | ||||||||||
Gas (per Mcf) | 3.22 | 4.44 | (27)% | 3.38 | 4.60 | (27)% | ||||||||||||||
NGL (per Bbl) | 16.12 | 35.47 | (55)% | 18.23 | 35.60 | (49)% | ||||||||||||||
Equivalent (per BOE) | $ | 29.92 | $ | 47.04 | (36)% | $ | 32.22 | $ | 47.02 | (31)% | ||||||||||
Net production volumes: | ||||||||||||||||||||
Oil (MMBbl) | 4.5 | 4.0 | 13% | 14.8 | 11.6 | 28% | ||||||||||||||
Gas (Bcf) | 43.3 | 35.6 | 22% | 133.5 | 109.1 | 22% | ||||||||||||||
NGL (MMBbl) | 4.3 | 3.2 | 35% | 12.2 | 9.2 | 32% | ||||||||||||||
MMBOE | 16.1 | 13.1 | 22% | 49.3 | 39.0 | 27% | ||||||||||||||
Average net daily production: | ||||||||||||||||||||
Oil (MBbl per day) | 49.1 | 43.5 | 13% | 54.3 | 42.3 | 28% | ||||||||||||||
Gas (MMcf per day) | 471.1 | 386.5 | 22% | 488.9 | 399.5 | 22% | ||||||||||||||
NGL (MBbl per day) | 46.8 | 34.6 | 35% | 44.8 | 33.8 | 32% | ||||||||||||||
MBOE (per day) | 174.5 | 142.5 | 22% | 180.6 | 142.7 | 27% | ||||||||||||||
Per BOE Data: | ||||||||||||||||||||
Realized price, before the effects of derivative settlements | $ | 22.84 | $ | 47.06 | (51)% | $ | 24.36 | $ | 48.63 | (50)% | ||||||||||
Lease operating expense | 3.86 | 4.58 | (16)% | 3.70 | 4.27 | (13)% | ||||||||||||||
Transportation costs | 6.27 | 6.22 | 1% | 5.99 | 6.25 | (4)% | ||||||||||||||
Production taxes | 0.96 | 2.32 | (59)% | 1.16 | 2.30 | (50)% | ||||||||||||||
Ad valorem tax expense | 0.40 | 0.49 | (18)% | 0.39 | 0.51 | (24)% | ||||||||||||||
General and administrative | 2.35 | 3.18 | (26)% | 2.52 | 2.95 | (15)% | ||||||||||||||
Operating profit, before the effects of derivative settlements | $ | 9.00 | $ | 30.27 | (70)% | $ | 10.60 | $ | 32.35 | (67)% | ||||||||||
Derivative settlement gain (loss) | 7.08 | (0.02 | ) | 35,500% | 7.86 | (1.61 | ) | 588% | ||||||||||||
Operating profit, including the effects of derivative settlements | $ | 16.08 | $ | 30.25 | (47)% | $ | 18.46 | $ | 30.74 | (40)% | ||||||||||
Depletion, depreciation, amortization, and | ||||||||||||||||||||
asset retirement obligation liability accretion | $ | 15.19 | $ | 13.97 | 9% | $ | 13.81 | $ | 14.07 | (2)% | ||||||||||
SM ENERGY COMPANY | ||||||||||||||||
FINANCIAL HIGHLIGHTS (unaudited) | ||||||||||||||||
September 30, 2015 | ||||||||||||||||
Condensed Consolidated Statements of Operations | ||||||||||||||||
(in thousands, except per share amounts) | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Operating revenues: | ||||||||||||||||
Oil, gas, and NGL production revenue | $ | 366,615 | $ | 617,207 | $ | 1,201,186 | $ | 1,894,977 | ||||||||
Net gain (loss) on divestiture activity | 2,415 | (5,432 | ) | 38,497 | 52 | |||||||||||
Other operating revenues | 2,121 | 7,011 | 13,548 | 31,457 | ||||||||||||
Total operating revenues and other income | 371,151 | 618,786 | 1,253,231 | 1,926,486 | ||||||||||||
Operating expenses: | ||||||||||||||||
Oil, gas, and NGL production expense | 184,568 | 178,390 | 554,404 | 519,697 | ||||||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 243,879 | 183,259 | 680,984 | 548,255 | ||||||||||||
Exploration | 19,679 | 34,556 | 82,627 | 80,161 | ||||||||||||
Impairment of proved properties | 55,990 | — | 124,430 | — | ||||||||||||
Abandonment and impairment of unproved properties | 6,600 | 15,522 | 24,046 | 18,487 | ||||||||||||
General and administrative | 37,782 | 41,696 | 124,026 | 114,862 | ||||||||||||
Change in Net Profits Plan liability | (4,364 | ) | (6,399 | ) | (13,174 | ) | (15,280 | ) | ||||||||
Derivative (gain) loss | (212,253 | ) | (190,661 | ) | (285,491 | ) | 33,470 | |||||||||
Other operating expenses | 7,166 | 5,444 | 34,589 | 19,505 | ||||||||||||
Total operating expenses | 339,047 | 261,807 | 1,326,441 | 1,319,157 | ||||||||||||
Income (loss) from operations | 32,104 | 356,979 | (73,210 | ) | 607,329 | |||||||||||
Non-operating income (expense): | ||||||||||||||||
Other, net | 27 | (672 | ) | 623 | (2,493 | ) | ||||||||||
Interest expense | (33,157 | ) | (22,621 | ) | (96,583 | ) | (70,851 | ) | ||||||||
Loss on extinguishment of debt | — | — | (16,578 | ) | — | |||||||||||
Income (loss) before income taxes | (1,026 | ) | 333,686 | (185,748 | ) | 533,985 | ||||||||||
Income tax (expense) benefit | 4,140 | (124,748 | ) | 78,296 | (199,660 | ) | ||||||||||
Net income (loss) | $ | 3,114 | $ | 208,938 | $ | (107,452 | ) | $ | 334,325 | |||||||
Basic weighted-average common shares outstanding | 67,961 | 67,379 | 67,638 | 67,169 | ||||||||||||
Diluted weighted-average common shares outstanding | 68,119 | 68,430 | 67,638 | 68,258 | ||||||||||||
Basic net income (loss) per common share | $ | 0.05 | $ | 3.10 | $ | (1.59 | ) | $ | 4.98 | |||||||
Diluted net income (loss) per common share | $ | 0.05 | $ | 3.05 | $ | (1.59 | ) | $ | 4.90 | |||||||
SM ENERGY COMPANY | |||||||
FINANCIAL HIGHLIGHTS (unaudited) | |||||||
September 30, 2015 | |||||||
Condensed Consolidated Balance Sheets | |||||||
(in thousands, except share amounts) | September 30, | December 31, | |||||
ASSETS | 2015 | 2014 | |||||
Current assets: | |||||||
Cash and cash equivalents | $ | 197 | $ | 120 | |||
Accounts receivable | 171,067 | 322,630 | |||||
Derivative asset | 347,299 | 402,668 | |||||
Prepaid expenses and other | 19,114 | 19,625 | |||||
Total current assets | 537,677 | 745,043 | |||||
Property and equipment (successful efforts method): | |||||||
Proved oil and gas properties | 7,468,331 | 7,348,436 | |||||
Less - accumulated depletion, depreciation, and amortization | (3,240,109 | ) | (3,233,012 | ) | |||
Unproved oil and gas properties | 381,869 | 532,498 | |||||
Wells in progress | 452,436 | 503,734 | |||||
Oil and gas properties held for sale, net of accumulated depletion, depreciation and amortization of $74,894 and $22,482, respectively | 29,173 | 17,891 | |||||
Other property and equipment, net of accumulated depreciation of $43,197 and $37,079, respectively | 359,339 | 334,356 | |||||
Total property and equipment, net | 5,451,039 | 5,503,903 | |||||
Noncurrent assets: | |||||||
Derivative asset | 147,530 | 189,540 | |||||
Other noncurrent assets | 77,615 | 78,214 | |||||
Total other noncurrent assets | 225,145 | 267,754 | |||||
Total Assets | $ | 6,213,861 | $ | 6,516,700 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued expenses | $ | 361,734 | $ | 640,684 | |||
Derivative liability | 2,900 | — | |||||
Deferred tax liability | 120,563 | 142,976 | |||||
Other current liabilities | — | 1,000 | |||||
Total current liabilities | 485,197 | 784,660 | |||||
Noncurrent liabilities: | |||||||
Revolving credit facility | 184,000 | 166,000 | |||||
Senior Notes | 2,350,000 | 2,200,000 | |||||
Asset retirement obligation | 118,153 | 120,867 | |||||
Net Profits Plan liability | 13,962 | 27,136 | |||||
Deferred income taxes | 833,352 | 891,681 | |||||
Derivative liability | 2,019 | 70 | |||||
Other noncurrent liabilities | 40,341 | 39,631 | |||||
Total noncurrent liabilities | 3,541,827 | 3,445,385 | |||||
Stockholders’ equity: | |||||||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 67,968,714 and 67,463,060, respectively | 680 | 675 | |||||
Additional paid-in capital | 298,438 | 283,295 | |||||
Retained earnings | 1,899,803 | 2,013,997 | |||||
Accumulated other comprehensive loss | (12,084 | ) | (11,312 | ) | |||
Total stockholders’ equity | 2,186,837 | 2,286,655 | |||||
Total Liabilities and Stockholders’ Equity | $ | 6,213,861 | $ | 6,516,700 | |||
FINANCIAL HIGHLIGHTS (unaudited) | ||||||||||||||||
September 30, 2015 | ||||||||||||||||
Condensed Consolidated Statements of Cash Flows | ||||||||||||||||
(in thousands) | ||||||||||||||||
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 3,114 | $ | 208,938 | $ | (107,452 | ) | $ | 334,325 | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Net (gain) loss on divestiture activity | (2,415 | ) | 5,432 | (38,497 | ) | (52 | ) | |||||||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 243,879 | 183,259 | 680,984 | 548,255 | ||||||||||||
Exploratory dry hole expense | (36 | ) | 16,385 | 22,860 | 22,844 | |||||||||||
Impairment of proved properties | 55,990 | — | 124,430 | — | ||||||||||||
Abandonment and impairment of unproved properties | 6,600 | 15,522 | 24,046 | 18,487 | ||||||||||||
Stock-based compensation expense | 7,277 | 10,227 | 20,492 | 24,568 | ||||||||||||
Change in Net Profits Plan liability | (4,364 | ) | (6,399 | ) | (13,174 | ) | (15,280 | ) | ||||||||
Derivative (gain) loss | (212,253 | ) | (190,661 | ) | (285,491 | ) | 33,470 | |||||||||
Derivative cash settlements | 105,688 | (274 | ) | 397,307 | (62,894 | ) | ||||||||||
Amortization of deferred financing costs | 1,911 | 1,479 | 5,803 | 4,433 | ||||||||||||
Non-cash loss on extinguishment of debt | — | — | 4,123 | — | ||||||||||||
Deferred income taxes | 4,168 | 124,269 | (80,388 | ) | 198,180 | |||||||||||
Plugging and abandonment | (2,154 | ) | (2,974 | ) | (5,540 | ) | (6,193 | ) | ||||||||
Other, net | 4,104 | 1,893 | 3,670 | (2,934 | ) | |||||||||||
Changes in current assets and liabilities: | ||||||||||||||||
Accounts receivable | 66,385 | 9,034 | 105,336 | 6,476 | ||||||||||||
Prepaid expenses and other | (2,346 | ) | (1,068 | ) | 587 | 234 | ||||||||||
Accounts payable and accrued expenses | (40,207 | ) | (15,093 | ) | (74,247 | ) | (28,797 | ) | ||||||||
Net cash provided by operating activities | 235,341 | 359,969 | 784,849 | 1,075,122 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Net proceeds from the sale of oil and gas properties | 115 | (4,953 | ) | 335,103 | 41,868 | |||||||||||
Capital expenditures | (287,741 | ) | (539,282 | ) | (1,261,871 | ) | (1,317,862 | ) | ||||||||
Acquisition of proved and unproved oil and gas properties | (500 | ) | (360,658 | ) | (7,088 | ) | (459,277 | ) | ||||||||
Other, net | 6 | 1,543 | (990 | ) | (714 | ) | ||||||||||
Net cash used in investing activities | (288,120 | ) | (903,350 | ) | (934,846 | ) | (1,735,985 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Proceeds from credit facility | 374,000 | 536,500 | 1,604,500 | 536,500 | ||||||||||||
Repayment of credit facility | (312,000 | ) | (146,500 | ) | (1,586,500 | ) | (146,500 | ) | ||||||||
Net proceeds from Senior Notes | (606 | ) | — | 490,951 | — | |||||||||||
Repayment of Senior Notes | — | — | (350,000 | ) | — | |||||||||||
Proceeds from sale of common stock | — | 408 | 3,157 | 2,898 | ||||||||||||
Dividends paid | — | — | (3,373 | ) | (3,353 | ) | ||||||||||
Net share settlement from issuance of stock awards | (8,502 | ) | (10,576 | ) | (8,502 | ) | (10,576 | ) | ||||||||
Other, net | 2 | 24 | (159 | ) | (85 | ) | ||||||||||
Net cash provided by financing activities | 52,894 | 379,856 | 150,074 | 378,884 | ||||||||||||
Net change in cash and cash equivalents | 115 | (163,525 | ) | 77 | (281,979 | ) | ||||||||||
Cash and cash equivalents at beginning of period | 82 | 163,794 | 120 | 282,248 | ||||||||||||
Cash and cash equivalents at end of period | $ | 197 | $ | 269 | $ | 197 | $ | 269 | ||||||||
SM ENERGY COMPANY | ||||||||||||||||
FINANCIAL HIGHLIGHTS (unaudited) | ||||||||||||||||
September 30, 2015 | ||||||||||||||||
Adjusted Net Income (Loss) | ||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||
Reconciliation of net income (loss) (GAAP) | ||||||||||||||||
to adjusted net income (loss) (Non-GAAP): | ||||||||||||||||
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Reported net income (loss) (GAAP) | $ | 3,114 | $ | 208,938 | $ | (107,452 | ) | $ | 334,325 | |||||||
Adjustments net of tax: (1) | ||||||||||||||||
Change in Net Profits Plan liability | (2,758 | ) | (4,019 | ) | (8,326 | ) | (9,596 | ) | ||||||||
Derivative (gain) loss | (134,144 | ) | (119,735 | ) | (180,430 | ) | 21,019 | |||||||||
Derivative settlement gain (loss) (2) | 71,855 | (172 | ) | 245,038 | (39,497 | ) | ||||||||||
Net (gain) loss on divestiture activity | (1,526 | ) | 3,411 | (24,330 | ) | (33 | ) | |||||||||
Impairment of proved properties | 35,386 | — | 78,640 | — | ||||||||||||
Abandonment and impairment of unproved properties | 4,171 | 9,748 | 15,197 | 11,610 | ||||||||||||
Loss on extinguishment of debt | — | — | 10,477 | — | ||||||||||||
Unwinding of derivatives contracts related to Mid-continent | — | — | (9,688 | ) | — | |||||||||||
Other, net (3) | 623 | 467 | 5,397 | (5,092 | ) | |||||||||||
Adjusted net income (loss) (Non-GAAP) (4) | $ | (23,279 | ) | $ | 98,638 | $ | 24,523 | $ | 312,736 | |||||||
Diluted weighted-average common shares outstanding: (5) | 67,961 | 68,430 | 68,018 | 68,258 | ||||||||||||
Adjusted net income (loss) per diluted common share: | $ | (0.34 | ) | $ | 1.44 | $ | 0.36 | $ | 4.58 | |||||||
(1) Adjustments are shown net of tax and are calculated using a tax rate of 36.8% for the three and nine months ended September 30, 2015, and 37.2% for the three and nine months ended September 30, 2014, which approximates the Company's statutory tax rate for the respective periods, as adjusted for ordinary permanent differences. | ||||||||||||||||
(2) Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities. | ||||||||||||||||
(3) For the three and nine-month periods ended September 30, 2015, the adjustment is related to the impairment of materials inventory and an estimated adjustment relating to claims on royalties on certain Federal and Indian leases, which are included in other operating expenses on the Company's condensed consolidated statements of operations. For the three and nine-month periods ended September 30, 2014, adjustments include items related to settlements from the previously disclosed litigation against Endeavour Operating Corporation. These items are included as a portion of other operating revenues and non-operating expense, other, net, on the Company's condensed consolidated statements of operations. | ||||||||||||||||
(4) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and generally are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash adjustments and impairments such as the change in the Net Profits Plan liability, derivative (gain) loss net of derivative settlements, impairment of properties, and (gain) loss on divestiture activity. The non-GAAP measure of adjusted net income is presented because management believes it provides useful additional information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry and many investors use the published research of industry research analysts in making investment decisions. Adjusted net income should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies. | ||||||||||||||||
(5) For periods where the Company reports a GAAP net loss, the diluted weighted average share count is calculated using potentially dilutive securities related to unvested Restricted Stock Units and contingent Performance Share Units. On a GAAP basis, these items are not treated as dilutive securities in periods where the Company reports a GAAP loss for the period. Additionally, in periods where an adjusted net loss is calculated, all potentially dilutive shares are anti-dilutive and excluded from the calculation of adjusted net loss per diluted common share. | ||||||||||||||||
SM ENERGY COMPANY | ||||||||||||||||
FINANCIAL HIGHLIGHTS (unaudited) | ||||||||||||||||
September 30, 2015 | ||||||||||||||||
Adjusted EBITDAX (3) | ||||||||||||||||
(in thousands) | ||||||||||||||||
Reconciliation of net income (loss) (GAAP) to adjusted EBITDAX (Non-GAAP) to net cash provided by operating activities (GAAP) | ||||||||||||||||
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) (GAAP) | $ | 3,114 | $ | 208,938 | $ | (107,452 | ) | $ | 334,325 | |||||||
Interest expense | 33,157 | 22,621 | 96,583 | 70,851 | ||||||||||||
Other non-operating (income) expense, net | (27 | ) | 672 | (623 | ) | 2,493 | ||||||||||
Income tax expense (benefit) | (4,140 | ) | 124,748 | (78,296 | ) | 199,660 | ||||||||||
Depreciation, depletion, amortization, and asset retirement obligation liability accretion | 243,879 | 183,259 | 680,984 | 548,255 | ||||||||||||
Exploration (1) | 17,798 | 32,155 | 77,298 | 74,696 | ||||||||||||
Impairment of proved properties | 55,990 | — | 124,430 | — | ||||||||||||
Abandonment and impairment of unproved properties | 6,600 | 15,522 | 24,046 | 18,487 | ||||||||||||
Stock-based compensation expense | 7,277 | 10,227 | 20,492 | 24,568 | ||||||||||||
Derivative (gain) loss | (212,253 | ) | (190,661 | ) | (285,491 | ) | 33,470 | |||||||||
Derivative settlement gain (loss) (2) | 113,695 | (274 | ) | 387,719 | (62,894 | ) | ||||||||||
Change in Net Profits Plan liability | (4,364 | ) | (6,399 | ) | (13,174 | ) | (15,280 | ) | ||||||||
Net (gain) loss on divestiture activity | (2,415 | ) | 5,432 | (38,497 | ) | (52 | ) | |||||||||
Loss on extinguishment of debt | — | — | 16,578 | — | ||||||||||||
Other, net | 1,045 | — | 3,901 | — | ||||||||||||
Adjusted EBITDAX (Non-GAAP) | 259,356 | 406,240 | 908,498 | 1,228,579 | ||||||||||||
Interest expense | (33,157 | ) | (22,621 | ) | (96,583 | ) | (70,851 | ) | ||||||||
Other non-operating income (expense), net | 27 | (672 | ) | 623 | (2,493 | ) | ||||||||||
Income tax (expense) benefit | 4,140 | (124,748 | ) | 78,296 | (199,660 | ) | ||||||||||
Exploration (1) | (17,798 | ) | (32,155 | ) | (77,298 | ) | (74,696 | ) | ||||||||
Exploratory dry hole expense | (36 | ) | 16,385 | 22,860 | 22,844 | |||||||||||
Amortization of deferred financing costs | 1,911 | 1,479 | 5,803 | 4,433 | ||||||||||||
Deferred income taxes | 4,168 | 124,269 | (80,388 | ) | 198,180 | |||||||||||
Plugging and abandonment | (2,154 | ) | (2,974 | ) | (5,540 | ) | (6,193 | ) | ||||||||
Loss on extinguishment of debt | — | — | (12,455 | ) | — | |||||||||||
Other, net | 3,059 | 1,893 | (231 | ) | (2,934 | ) | ||||||||||
Changes in current assets and liabilities | 15,825 | (7,127 | ) | 41,264 | (22,087 | ) | ||||||||||
Net cash provided by operating activities (GAAP) | $ | 235,341 | $ | 359,969 | $ | 784,849 | $ | 1,075,122 | ||||||||
(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying condensed consolidated statements of operations because of the component of stock-based compensation expense recorded to exploration. | ||||||||||||||||
(2) Derivative settlement gain (loss) is reported net of the change in accrued settlements between periods in the derivative cash settlements line item on the condensed consolidated statements of cash flows within net cash provided by operating activities. | ||||||||||||||||
(3) Adjusted EBITDAX represents income (loss) before interest expense, other non-operating income or expense, income taxes, depreciation, depletion, amortization, and accretion expense, exploration expense, property impairments, non-cash stock based compensation expense, derivative gains and losses net of settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors and analysts, as a performance measure, for analysis of the Company's ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to a financial covenant under its credit facility based on its debt to adjusted EBITDAX ratio. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. | ||||||||||||||||