SandRidge Energy, Inc. Reports Financial and Operational Results for Third Quarter of 2017

OKLAHOMA CITY, Nov. 1, 2017 /PRNewswire/ -- SandRidge Energy, Inc. (the "Company" or "SandRidge") (NYSE:SD) today announced financial and operational results for the quarter ended September 30, 2017. Additionally, the Company will host a conference call to discuss these results on November 2, at 8:00 a.m. CT (833-245-9650, International: 647-689-4222 – passcode: 94553818). Presentation slides will be available on the Company's website, www.sandridgeenergy.com, under Investor Relations/Events.

Operational Results and Activity

Production for the third quarter was 3.6 MMBoe (27% oil, 23% NGLs and 50% natural gas). The Company's Mid-Continent assets produced approximately 93% of total production, with its North Park Basin and Permian assets making up the balance. As more NW STACK and North Park wells are brought to sales, oil is expected to become a larger percentage of total production. During the quarter, the Company averaged two rigs in the NW STACK targeting the Meramec and one rig targeting multiple benches of the Niobrara in the North Park Basin.  

Financial Results

The Company reported a net loss of $8 million, or $0.25 per share, and net cash provided by operating activities of $44 million for the third quarter of 2017. When adjusting these reported amounts for items that are typically excluded by the investment community on the basis that such items affect the comparability of results, the Company's "adjusted net income" amounted to $12 million, or $0.35 per share, and "operating cash flow" totaled $46 million. Earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for certain other items, otherwise referred to as "adjusted EBITDA," for the third quarter was $42 million.⁽¹⁾

James Bennett, SandRidge President and CEO said, "As we near the end of the year, we remain committed to our strategy of balance sheet preservation and cost reduction while prudently developing our assets. In Oklahoma's NW STACK, successful Meramec drilling above horizontal Osage production demonstrates stacked pay and supports future development of the deeper Osage zone. In Colorado'sNorth Park Basin, recent drilling confirms production from all four Niobrara benches (A, B, C and D), proving additional zones and increasing our future drilling inventory. Our previously announced Drilling Participation Agreement will fund continued delineation of the NW STACK, allowing for capital reallocation toward a growing opportunity set in the North Park Basin. Ongoing success with our cost reduction initiatives is reflected in our updated LOE and G&A guidance, which reduces cash costs another $7 million this year. As we prepare our 2018 budget, our undivided focus will be directed toward returns on capital and resource value creation, supported by our strategic emphasis on oil-weighted development."

Highlights During and Subsequent to the Third Quarter

Confirmed All Four North Park Basin Niobrara Benches (A, B, C and D) Productive

Achieved $0.5 Million D&C Capital Reduction on North Park Niobrara Two-Mile XRLs

Spud Initial Wells Under NW STACK Drilling Participation Agreement  

Confirmed Meramec/Osage Stacked Pay in NW STACK Spacing Test

Drilled First SandRidge NW STACK Well in Dewey County, Oklahoma

Lowered Lease Operating Expense Guidance to $6.90-$7.25 from $7.00-$7.50

Lowered Adjusted G&A per Boe Guidance to $4.00-$4.20 from $4.25-$4.50

Net Loss of $8 Million and Adjusted Net Income of $12 Million

Adjusted EBITDA of $42 Million

Capital Expenditures of $71 Million

Production of 3.6 MMBoe (27% Oil, 23% NGLs and 50% Natural Gas)

$515 Million of Liquidity Including $98 Million of Cash and $417 Million Capacity Under Credit Facility (Net of Letters of Credit)

Confirmed $425 Million Borrowing Base Under Credit Facility

Updated 2017 Operational Guidance

The Company is updating its operational guidance to reflect cost savings related to lease operating expense and G&A reduction initiatives. These savings reflect the removal of approximately $7 million from the Company's current cost structure, at the midpoint of guidance.

More information regarding operational guidance updates and capital budget details can be found below on page 6 of this release.

Mid-Continent Assets in Oklahoma

• Third quarter production of 3.3 MMBoe (36.0 MBoepd, 22% oil, 24% NGLs, 54% natural gas)
• Drilled first SandRidge Dewey County Meramec well with a 30-Day IP of 598 Boepd (71% oil)
• Confirmed Meramec/Osage stacked pay with Meramec well producing a 30-Day IP of 397 Boepd (88% oil)
• Spud initial wells under NW STACK Drilling Participation Agreement
• Averaged two rigs targeting the Meramec during the quarter
• Drilled seven SRLs and two XRLs during the quarter and brought two SRLs and three XRLs online

NW STACK Highlights and Developments

NW STACK highlights from the third quarter include extension of Meramec production south into Dewey County and the confirmation of stacked pay. The Regina 1915 1-18H SRL is the Company's first Meramec well drilled in Dewey County, Oklahoma. Producing a 30-Day IP of 598 Boepd (71% oil), this well extends the Company's production and resource potential beyond Major, Woodward and Garfield counties. In Major County, the Company confirmed Meramec/Osage stacked pay by drilling a Meramec well above existing horizontal Osage production. The Audra Claire 2015 1-24H, producing a 30-Day IP of 397 Boepd (88% oil) from the Meramec, supports stacked pay potential in the NW STACK. As part of the Company's strategy to initially develop the Meramec, this spacing test supports future development of the Osage.

During the fourth quarter, the Company will spend approximately $15 million completing wells drilled in the third quarter and running two rigs under the Drilling Participation Agreement. The two rigs will continue to drill SRLs and XRLs targeting the Meramec where drilling and completion costs are $4.4 million and $6.5 million, respectively.     

NW STACK Drilling Participation Agreement

As previously announced, the Company executed a $200 million development agreement (the "Drilling Participation Agreement") with a private investment fund ("Counterparty") to develop SandRidge Meramec operated wells in dedicated sections, primarily in Major and Woodward Counties. Under the Drilling Participation Agreement, the Counterparty will fund an initial $100 million tranche for its share of drilling and completion costs, receiving a wellbore-only working interest subject to reversionary hurdles.

The Company initiated the first wells under the Drilling Participation Agreement during the quarter and will continue running two rigs under its terms. Designated as operator, the Company is responsible for the selection, location and scheduling of wells drilled. Following the initial tranche of wells and funding, a second $100 million tranche will be available subject to mutual agreement.

Niobrara Asset in North Park Basin, Jackson County, Colorado

• Third quarter oil production of 128 MBo (1.4 MBopd)
• Confirmed all four North Park Basin Niobrara benches (A, B, C, and D) productive
• Achieved Niobrara XRL D&C capital reduction of $0.5 million due to pad drilling 
• One rig targeting the Niobrara during the quarter
• Drilled three XRLs and brought two XRLs online during the quarter

During the quarter, the Company completed and brought online two XRLs, the Grizzly 2-1H36 and Grizzly 4-1H36, which are currently flowing back. These wells established oil production in the Niobrara A and B benches, confirming all four Niobrara benches (A, B, C and D) productive which expands the Company's oil resource value.

In addition to growing its inventory, the Company has continued to capture efficiencies in the North Park Basin. The Grizzly wells were each drilled in 12 days, surpassing cycle time expectations by 20%. Furthermore, four additional XRLs were drilled in less than 14 days each as part of a recent 80 acre spacing test. These cycle time achievements and numerous other pad drilling efficiencies have successfully led to reduced drilling and completion costs of $6.7 million, compared to $7.2 million where full rig mobilization is required.

During the fourth quarter, the Company will spend approximately $34 million of capital completing wells drilled in the third quarter and running one rig drilling Niobrara XRLs. The Company's 2017 drilling program will hold over 105,000 acres by production or federal unit, which represents 85% of its current 123,000 net acre position. Lastly, $13 million will be invested to construct central tank batteries and infrastructure in support of production brought online this year and into 2018. 

Other Operational Activities

During the third quarter, Permian Central Basin Platform properties produced 127 MBoe (1.4 MBoepd, 80% oil, 13% NGLs, 7% natural gas).

Key Financial Highlights and Results

Third Quarter Results

• Net loss of $8 million, or $0.25 per share, for third quarter 2017 compared to a $404 million loss, or $0.56 per share, in third quarter of 2016
• Adjusted net income of $12 million, or $0.35 per diluted share, for third quarter 2017 compared to adjusted net income of $25 million, or $0.04 per diluted share, in third quarter 2016
• Adjusted EBITDA was $42 million for third quarter 2017 compared to $65 million in third quarter 2016
• Net cash provided by operating activities of $44 million for third quarter of 2017 compared to $75 million for third quarter of 2016
• Operating cash flow of $46 million for third quarter 2017 compared to $32 million in third quarter 2016

First Nine Months of 2017

• Net Income of $66 million, or $2.06 per diluted share, for the first nine months of 2017 compared to a $1.2 billion loss, or $1.76 per share, for the first nine months of 2016 
• Adjusted net income of $41 million, or $1.27 per diluted share, for the first nine months of 2017 compared to an adjusted net loss of $93 million, or $0.13 per share, for the first nine months of 2016
• Adjusted EBITDA was $144 million for the first nine months of 2017 compared to $167 million for the first nine months of 2016
• Net cash provided by operating activities of $148 million for the first nine months of 2017 compared to $64 million used in the first nine months of 2016
• Operating cash flow of $142 million for the first nine months of 2017 compared to negative $60 million for the first nine months of 2016

Capitalization & Liquidity

• 35.6 million shares outstanding
• $600 million reserve-based credit facility with confirmed $425 million borrowing base
• Liquidity of $515 million including $98 million of cash and $417 million capacity under the credit facility, net of outstanding letters of credit
• Outstanding debt consists of a $38 million note secured by the Company's real estate, resulting in zero net debt

Hedging

In 2017, the Company has approximately 3.3 million barrels of oil hedged at an average WTI price of $52.24 as well as 32.9 billion cubic feet of natural gas hedged at an average price of $3.20 per MMBtu. 2017 oil hedges represent 78% of the midpoint of current oil volume guidance. 2017 gas hedges represent 77% of the midpoint of current gas volume guidance.

For 2018, the Company has approximately 2.4 million barrels of oil hedged at an average WTI price of $54.59 as well as 17.3 billion cubic feet of natural gas hedged at an average price of $3.16 per MMBtu.

Conference Call Information

The Company will host a conference call to discuss these results on Thursday, November 2, 2017 at 8:00 am CT. The telephone number to access the conference call from within the U.S. is (833) 245-9650 and from outside the U.S. is (647) 689-4222. The passcode for the call is 94553818. An audio replay of the call will be available from November 2, 2017 until 11:59 pm CT on December 2, 2017. The number to access the conference call replay from within the U.S. is (800) 585-8367 and from outside the U.S. is (416) 621-4642. The passcode for the replay is 94553818.

A live audio webcast of the conference call will also be available via SandRidge's website, www.sandridgeenergy.com, under Investor Relations/Events. The webcast will be archived for replay on the Company's website for 30 days.

2017 Operational and Capital Expenditure Guidance

The table below highlights reductions to the Company's lease operating expense and adjusted G&A guidance as well as raised production severance tax guidance.

Additional 2017 Guidance detail is available on the Company's website, www.sandridgeenergy.com, under Investor Relations/Financial Information/Guidance.

Operational and Financial Statistics

Upon emergence from Chapter 11 reorganization, the Company elected to adopt fresh start accounting effective October 1, 2016. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after October 1, 2016 will not be comparable with the financial statements prior to that date. References to the "Successor" refer to SandRidge subsequent to adoption of fresh start accounting. References to the "Predecessor" refer to SandRidge prior to adoption of fresh start accounting.

Information regarding the Company's production, pricing, costs and earnings is presented below:

Capital Expenditures   

The table below presents actual results of the Company's capital expenditures for the three and nine-month periods ended September 30, 2017 at the same level of detail as its full year capital expenditure guidance.

Derivative Contracts

The table below sets forth the Company's consolidated oil and natural gas price swaps for 2017 and 2018 as of October 27, 2017:

Capitalization

The Company's capital structure as of September 30, 2017 and December 31, 2016 is presented below:

Non-GAAP Financial Measures

Adjusted net income, operating cash flow, adjusted EBITDA, adjusted G&A per Boe, and net debt are non-GAAP financial measures.

The Company defines adjusted net income as net income before asset impairment, loss (gain) on derivative contracts, cash received upon settlement of derivative contracts, restructuring costs, drilling participation agreement transaction costs, oil field services – exit costs, reorganization items, net, employee incentive and retention and other expenses. The Company defines operating cash flow as net cash provided by (used in) operating activities before changes in operating assets and liabilities. It defines EBITDA as net (loss) income before income tax (benefit) expense, interest expense, depreciation and amortization – other and depreciation and depletion – oil and natural gas. Adjusted EBITDA, as presented herein, is EBITDA excluding asset impairment, stock-based compensation, loss (gain) on derivative contracts, cash received upon settlement of derivative contracts, loss on settlement of contract, restructuring costs, oil field services – exit costs, gain on extinguishment of debt, reorganization items employee incentive and retention and other various items. The Company defines adjusted G&A per Boe as general and administrative expense per Boe adjusted for certain non-recurring items, expressed on a per-Boe basis, and less stock-based compensation expense, expressed on a per-Boe basis.

Operating cash flow and adjusted EBITDA are supplemental financial measures used by the Company's management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the Company's ability to internally fund exploration and development activities and to service or incur additional debt. The Company also uses these measures because operating cash flow and adjusted EBITDA relate to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow and adjusted EBITDA allow the Company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. These measures should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles ("GAAP"). Adjusted EBITDA should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the Company's adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

Management also uses the supplemental financial measure of adjusted net income (loss), which excludes asset impairment, (gain) loss on derivative contracts, cash received on settlement of derivative contracts, restructuring costs, drilling participation agreement transaction costs, oil field services – exit costs, reorganization items, employee incentive and retention and other non-cash items from income available (loss applicable) to common stockholders. Management uses this financial measure as an indicator of the Company's operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income (loss) is not a measure of financial performance under GAAP and should not be considered a substitute for loss applicable to common stockholders.

The Company reports and provides guidance on adjusted G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes adjusted G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry. This non-GAAP measure allows for the analysis of general and administrative spend without regard to stock-based compensation programs, and other non-recurring cash items which can vary significantly between companies. Adjusted G&A per Boe is not a measure of financial performance under GAAP and should not be considered a substitute for general and administrative expense per Boe. Therefore, the Company's Adjusted G&A per Boe may not be comparable to other companies' similarly titled measures.

The Company also uses the term net debt to determine the extent to which the Company's outstanding debt obligations would be satisfied by its cash and cash equivalents on hand. Management believes this metric is useful to investors in determining the Company's current leverage position following recent significant events subsequent to the period.

The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA and adjusted EBITDA and adjusted net income (loss).