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FANG · Diamondback Energy, Inc.

16 filings

10-K

FANG 10-K Annual Reports

Diamondback Energy, Inc. - 16 annual reports

Filing record · 2016–202610-K1210-Q328-K174

2025
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2025
Diamondback Energy, Inc. (FANG) reported its 2025 fiscal year results, demonstrating significant operational expansion and strategic capital allocation. The company successfully closed the Double Eagle Acquisition, adding approximately 40,000 net acres primarily in the Midland Basin, and completed the Viper Sitio Acquisition valued at approximately $4.0 billion, enhancing Viper's mineral and royalty interests in the Permian Basin. Diamondback also strategically divested non-core assets totaling $1.7 billion, including its stake in EPIC Crude Holdings and water assets, to optimize its portfolio and reduce debt. Operationally, Diamondback maintained capital discipline with $3.5 billion in cash capital expenditures, consistent with guidance. The company is focused on returning capital to shareholders, with at least 50% of Adjusted Free Cash Flow designated for dividends and stock repurchases, while also prioritizing debt reduction. Looking ahead to 2026, Diamondback plans for essentially flat production levels and estimates capital expenditures between $3.60 billion and $3.90 billion, signaling a continued focus on efficient development and shareholder returns.
Feb 25, 2026
2024
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2024
Diamondback Energy, Inc. (FANG) filed its Annual Report on Form 10-K for the fiscal year ended December 31, 2024. The report details significant strategic growth through major acquisitions, most notably the Endeavor Acquisition completed in September 2024. This acquisition substantially expanded Diamondback's acreage position and production base, primarily within the Permian Basin. The company continues to focus on capital discipline and operational efficiency, aiming to return capital to stockholders through its enhanced capital return program, which targets returning at least 50% of quarterly free cash flow. Diamondback is also actively managing its balance sheet, with a near-term goal to reduce net debt to $10 billion. Looking ahead, Diamondback has a pending acquisition of Double Eagle, which is expected to further bolster its acreage and drilling inventory in the Midland Basin, and has outlined a robust capital expenditure budget for 2025 to support development activities.
Feb 26, 2025
2023
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2023
Diamondback Energy, Inc. (FANG) has filed its 2023 Annual Report on Form 10-K, detailing its operational and financial performance. The company remains focused on the Permian Basin, a key U.S. oil-producing region, with a significant acreage position in both the Midland and Delaware Basins. Diamondback demonstrated production growth in 2023, driven by acquisitions and drilling activity, though average realized prices for oil and natural gas declined compared to 2022. The company continues its commitment to capital discipline and returning capital to shareholders through dividends and share repurchases. A significant development highlighted is the pending acquisition of Endeavor, announced in February 2024, which is expected to significantly expand Diamondback's scale and operational footprint.
Feb 22, 2024
2022
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2022
Diamondback Energy's FY2022 10-K shows a strong year driven by commodity prices: total revenue of $9.64 billion (up about 42% in oil, gas and NGL revenue to $9.57 billion) and net income attributable to the company of $4.39 billion, versus $2.18 billion in 2021. Production averaged 386,005 BOE/d, up about 3% year over year, with the mix at roughly 58% oil. The company generated $6.3 billion of operating cash flow and spent $1.9 billion on drilling, completions and infrastructure. Management held oil output flat and directed excess cash toward debt reduction (about $2.4 billion of senior notes retired), $1.1 billion of buybacks and a base-plus-variable dividend. Management commits to returning at least 75% of quarterly free cash flow, and it raised the annual base dividend 50% to $3.00 in 2022 and then to $3.20 in February 2023. The balance sheet is conservative, with total debt of about $6.2 billion, $157 million of cash and roughly $1.6 billion of undrawn revolver capacity. Liquidity stood at about $1.8 billion at year-end. Credit ratings are investment grade (BBB-/BBB/Baa2). Growth came mainly through acquisitions: FireBird (about 75,000 gross acres in the Midland Basin, closed November 2022) and Lario (about 25,000 gross acres, closed January 2023, for $814 million cash plus 4.33 million shares). Both were paid partly in stock, which lifted the share count. Pending divestitures of non-core assets total $439 million, and management has raised its non-core sale target to $1.0 billion for 2023. The 2023 plan calls for capital spending of $2.50 to $2.70 billion, which is about 37% above 2022, with 325 to 345 gross horizontal wells drilled. The company has 613 gross operated horizontal wells on its acreage. Key risks include commodity price volatility, Permian produced-water disposal restrictions, rising costs from inflation, the IRA's methane fee and corporate alternative minimum tax, and concentration of production in one basin with two purchasers representing 43% of revenue. The company recorded no impairment in 2022, and that stance depends on continued high trailing-twelve-month commodity prices.
Feb 23, 2023
2021
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2021
Diamondback Energy (FANG) closed 2021 as a much larger, more profitable company after the QEP Merger (March 2021, ~$987M in stock) and the Guidon Acquisition (February 2021, $375M cash plus stock). Net income attributable to Diamondback was $2.18 billion, versus a $4.52 billion loss in 2020 that was driven by a $6.0 billion non-cash ceiling-test impairment. Total revenue rose to $6.8 billion, and average production reached 375,348 BOE/d, up 25% in volume. Operating cash flow was $3.94 billion, and capital expenditures were held to about $1.5 billion, 11% below April 2021 guidance. Management is maintaining flat oil production and expects to spend $1.75–1.90 billion in 2022. Capital returns and balance sheet work were central to the year. Diamondback repurchased $431 million of stock under a new $2 billion program, paid $312 million in dividends, and retired roughly $3.2 billion of senior notes, including QEP and legacy Energen debt. Management says it will return at least 50% of quarterly free cash flow to stockholders, and the Q4 2021 dividend was raised 20% to $0.60 per share. Liquidity was about $2.2 billion at year end, comprising $0.7 billion of cash and $1.6 billion of undrawn revolver capacity. Total debt was about $6.7 billion, and the company carries investment-grade ratings of BBB-, Baa3, and BBB. The main risks are commodity-price exposure, reserve estimate uncertainty, and concentration in the Permian Basin. Approximately 33% of proved reserves are undeveloped. Roughly 9,314 gross identified drilling locations are economic at $50 WTI, but only 602 of those are booked as proved. Management also flagged Texas produced-water disposal restrictions, which may raise costs in parts of the Permian, and the company recorded $848 million in derivative losses for 2021, which reduced reported earnings.
Feb 24, 2022
2020
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2020
Diamondback Energy's FY2020 10-K shows a company sharply pressured by the COVID-19 demand shock and commodity price collapse, but positioned for recovery through disciplined capital cuts and a pending merger. Revenue fell about 29% to $2.8 billion, driven by an oil price drop to roughly $36 per barrel. The company recorded a $6.0 billion non-cash ceiling test impairment, producing a net loss attributable to Diamondback of $4.5 billion ($28.59 per share). Operating cash flow still remained solid at $2.1 billion, and capex was cut roughly in half for 2021 to $1.4–1.6 billion, with flat production targeted for Q4 2020 levels. The balance sheet carries about $5.8 billion of principal debt, with long-term debt of $5.6 billion and a $2.0 billion revolver of which $1.98 billion was undrawn at year-end. Management expects to retain investment-grade ratings. Pending transactions will add meaningful scale and leverage: the all-stock QEP Resources acquisition (about $2.2 billion including $1.6 billion of QEP net debt, expected to add Tier-1 Midland Basin inventory and $60–80 million of annual synergies) and the Guidon Acquisition (32,500 net Northern Midland Basin acres for $375 million cash plus 10.6 million shares). Pro forma debt after the QEP merger would be roughly $7.4 billion. Shareholder returns were reduced in 2020, with the $2 billion buyback suspended and expired, though the quarterly dividend was raised to $0.40 per share for Q4 2020. Key investor watch items include the pace of reserve and cash flow recovery, the QEP merger's closing risks (including nine lawsuits filed by QEP stockholders as of February 22, 2021), leverage after integration, and further ceiling test write-downs if commodity prices weaken. Proved reserves rose to 1,316 MMBOE, though 38% are undeveloped, and the 10,413-location drilling inventory is concentrated almost entirely in the Permian Basin.
Feb 25, 2021
2019
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2019
Diamondback Energy's FY2019 10-K shows a Permian-focused pure-play upstream business that grew sharply through the Energen merger and asset drop-downs, but finished the year with a weaker earnings profile. Total revenues rose 82% to $3.96 billion, and production averaged 282,972 BOE/d, up from 130,439 BOE/d in 2018. However, net income attributable to Diamondback fell to $240 million ($1.47 diluted EPS) from $846 million, largely because of an $790 million full-cost ceiling impairment in 2019, higher depletion ($1.45 billion DD&A), and $333 million of total other expense including a $108 million derivative loss and $172 million of net interest expense. The balance sheet expanded materially. Total long-term debt reached $5.4 billion, up from $4.5 billion, after the December 2019 issuance of $3.0 billion of senior notes that refinanced the $1.25 billion 4.750% notes. Liquidity remained solid, with $1.99 billion available under the $2.0 billion revolver and cash of $123 million. Operating cash flow was $2.7 billion versus $1.6 billion in 2018, against roughly $3.9 billion of investing outflows, which were funded largely by equity raised at Viper and Rattler and by debt. Management guided to a 2020 capital budget of $2.8 to $3.0 billion for 320 to 360 gross horizontal wells, and it expects full-year 2020 commodity sensitivity to remain high, given WTI prices that were already falling into early 2020. For shareholders, the company increased its quarterly dividend to $0.375 per share (announced February 14, 2020) and had repurchased about $598 million of stock under a $2 billion program, leaving $1.4 billion authorized. Key structural features include a consolidated but partly owned structure: Diamondback owns about 58% of Viper and 71% of Rattler, so a significant share of consolidated net income and cash flow is attributable to non-controlling interests. Investors should weigh the strong operating scale and cash generation against the 2019 impairment, the rising leverage, and concentration risk in the Permian Basin and a small set of oil purchasers.
Feb 27, 2020
2018-A
Diamondback Energy, Inc. Annual Report (Amendment), Year Ended Dec 31, 2018
This Form 10-K/A (Amendment No. 1) for Diamondback Energy, Inc. (FANG), fiscal year ended December 31, 2018, was filed on March 12, 2019, to add a Ryder Scott Company reserve report on the proved reserves of Energen Corporation, a wholly owned subsidiary acquired in the merger completed November 29, 2018. The amendment contains no financial statements and does not modify the original 10-K filed February 25, 2019. Its purpose is to correct an inadvertent omission, so the document is best read as a supplement to the original filing rather than a standalone update on Diamondback's results or financial condition. The Ryder Scott report, prepared under SEC pricing and reserve rules, estimates total proved reserves of 466,386 MBOE (thousand barrels of oil equivalent) for the Energen properties as of December 31, 2018. That total comprises 263,329 Mbbl of oil and condensate, 99,348 Mbbl of plant products, and 622,251 MMcf of gas. About 64.6% of proved reserves (301,423 MBOE) are proved developed producing, 0.01% are proved developed non-producing, and 35.4% (164,921 MBOE) are proved undeveloped. The evaluated properties, located in New Mexico and Texas, represent 99.5% of Energen's total proved reserves on an oil-equivalent basis. Undiscounted future net income is $10.98 billion, and discounted future net income at 10% is $5.06 billion. Liquids account for roughly 95% of future gross revenue from proved reserves. Investors should note the price sensitivity embedded in these figures. Reserves and income were calculated using 12-month average SEC benchmark prices, with WTI at $65.56/bbl and Henry Hub gas at $3.10/MMBtu. Realized prices after differentials were $56.99/bbl for oil, $22.64/bbl for NGLs, and $1.48/Mcf for gas, so the gas realization discount is wide. Actual results will vary with commodity prices, costs, and development timing, and 35% of the reserves are undeveloped. Company-wide metrics such as total production, capital budgets, and Diamondback's own reserve base must be taken from the original 10-K filed February 25, 2019, which this amendment does not restate.
Mar 12, 2019
2018
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2018
Diamondback Energy's FY2018 10-K shows a transformational year driven by the all-stock merger with Energen (closed November 29, 2018) and the Ajax, ExL and Drop-down transactions. Production averaged 130,439 BOE/d in 2018, up 65% from 79,224 BOE/d in 2017, and total revenues rose 81% to $2.18 billion. Net income attributable to Diamondback was $845.7 million, or $8.06 diluted EPS, compared with $482.3 million in 2017. Consolidated Adjusted EBITDA (a non-GAAP measure) reached $1.54 billion, up from $928 million. The balance sheet expanded sharply. Total assets rose to $21.6 billion from $7.8 billion, and long-term debt increased to $4.46 billion from $1.48 billion. Management guides to a 2019 drilling and infrastructure capex budget of $2.7 to $3.0 billion, 290 to 320 gross horizontal wells, and 18 to 22 rigs, and says it expects production growth of more than 27% year over year within cash flow. The company also initiated a $0.125 quarterly dividend in 2018 and plans a 50% increase starting in Q1 2019. Operating cash flow was $1.56 billion, and cash and equivalents ended the year at $215 million. Key risks for investors include commodity price exposure (about 72% of 2018 production was oil, and realized oil prices were 84% of NYMEX), a large leverage increase, integration of Energen (Energen was excluded from the internal control assessment), concentration of production in the Permian Basin, and a sharp oil price decline in late 2018 (WTI fell to $45.15 at year-end, versus a 2018 high of $77.41). The company is hedged for a portion of 2019 production, and its revolving credit facility had a $2.65 billion borrowing base with $1.5 billion drawn at year-end.
Feb 25, 2019
2017
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2017
Diamondback Energy's FY2017 10-K shows a transformational year driven by the February 2017 Delaware Basin acquisition (~$2.5B total consideration, adding roughly 100,000 gross acres) and a sharp production ramp. Total revenue rose 129% to $1.205 billion from $527 million, and average daily production grew 84% to 79,224 BOE/d, with oil at roughly 74% of volumes. Consolidated Adjusted EBITDA reached $928 million (vs. $388 million in 2016), and operating cash flow nearly tripled to $889 million. Net income attributable to Diamondback was $482 million, or $4.94 diluted EPS, helped by a $127.5 million tax benefit from releasing the valuation allowance and a $67.9 million benefit from the Tax Act's rate cut. The balance sheet expanded substantially. Total assets grew to $7.77 billion and stockholders' equity to $5.25 billion, while long-term debt rose to $1.48 billion. Proved reserves increased 63% to 335 MMBOE (about 70% oil), with 62% proved developed. Liquidity is solid: the revolver had $397 million drawn against a $1.8 billion borrowing base (elected commitment $1.0 billion), and in January 2018 the company issued $300 million of add-on 2025 notes and paid down $308.5 million of revolver debt. Management plans 2018 capex of $1.3–1.5 billion (up 60%) and 10–12 rigs, with 170–190 gross horizontal wells planned. The company also announced its first annual dividend ($0.50/share, paid quarterly starting Q1 2018). Key investor considerations include the concentration of production in the Permian Basin and a small number of purchasers (Shell 31%, Koch 19%, Enterprise 11%), commodity price sensitivity (WTI ranged $42–$60 in 2017), a large undeveloped inventory (about 3,800 gross locations, of which only 168 are booked as proved), and the need to keep rig activity sufficient to hold leases expiring in 2018. Viper Energy Partners, consolidated with about a 64% ownership stake, adds complexity through non-controlling interests.
Feb 15, 2018
2016
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2016
Diamondback Energy's FY2016 10-K shows a company transitioning from the 2015-2016 commodity downturn into a growth phase, financed by record equity raises and a large acquisition. Revenue rose 18% to $527.1 million on 30% higher production (43,031 BOE/d), but the company still posted a net loss attributable to common stockholders of $165.0 million, driven by a $245.5 million full-cost ceiling impairment and a $33.1 million loss on debt extinguishment. Adjusted EBITDA was $387.5 million, versus $449.2 million in 2015. The balance sheet changed materially. December 2016 and other 2016 equity offerings raised roughly $2.1 billion, and cash reached $1.67 billion at year-end, largely earmarked for the pending $1.62 billion cash Brigham Resources acquisition expected to close in February 2017. Long-term debt rose to $1.1 billion after issuing $500 million each of 4.750% 2024 and 5.375% 2025 senior notes. Proved reserves grew 31% to 205.5 MMBOE, about 68% oil, and the company guided to a 2017 drilling and infrastructure budget of $800 million to $1.0 billion (a 132% increase) with 6 to 10 rigs. Investors should weigh the upside from a large, oil-weighted inventory of 2,722 gross identified locations and a conservative leverage profile against risks from concentration in the Permian Basin, 98% operatorship (a positive control factor), reliance on a few purchasers (Shell 45% of revenue), a full-cost ceiling exposed to price declines, and the integration risk of the Brigham deal, whose reserve and production data were not yet verified by the company.
Feb 15, 2017
2015
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2015
Diamondback Energy (FANG) closed 2015 with a sharp deterioration in reported results driven by the collapse in oil prices, even as operational growth was strong. Total revenue fell about 10% to $446.7 million from $495.7 million, while average production rose 70% to 33,098 BOE/d, meaning realized pricing (average $36.98/BOE versus $69.74 in 2014) more than offset volume gains. The company recorded an $814.8 million non-cash full-cost ceiling impairment, producing a net loss attributable to Diamondback of $550.6 million, or $(8.74) per share, compared with net income of $193.8 million in 2014. Adjusted EBITDA still rose to $449.2 million from $398.3 million, and operating cash flow increased to $416.5 million, highlighting that the loss is largely non-cash. Balance sheet and liquidity remain conservative relative to the sector. Long-term debt fell to $495.5 million from $673.5 million, comprising $450 million of 7.625% senior notes due 2021, $11 million drawn on the Diamondback revolver (with $489 million of availability under a $500 million elected commitment), and $34.5 million at the Viper subsidiary. Total equity stands at $2.1 billion after three 2015 equity offerings raising about $650 million, and a further $254.5 million offering was completed in January 2016. Management cut the 2016 capital budget to $250-375 million (down 26%), plans to release one of three horizontal rigs in March 2016, and has no hedges beyond January-February 2016 Brent swaps. The key investor focus is the trade-off between a low-cost, oil-weighted Permian position (about 156.9 MMBOE of proved reserves, 67% oil, roughly 1,500 gross identified horizontal locations) and the risks from continued price weakness. Proved reserves are highly dependent on the price deck (the SEC 12-month average was $50.28/Bbl oil), 41% are proved undeveloped, and a lower price environment could trigger further write-downs and borrowing base reductions. Revenue concentration is high, with Shell Trading accounting for 59% of 2015 revenue.
Feb 19, 2016
2014
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2014
Diamondback Energy's FY2014 10-K shows a company transformed by scale. Revenue rose 138% to $495.7 million on production that grew 166% to 19,474 BOE/d, driven by drilling in the Permian Basin's Wolfberry play and roughly $1.35 billion of acquisitions in 2014 (including $845.8 million of leasehold purchases and a $523.3 million September deal). Net income attributable to Diamondback was $193.8 million ($3.64 diluted EPS), though much of the swing reflects a $127.5 million derivative gain tied to the late-2014 fall in oil prices rather than operating cash generation alone. Operating cash flow of $356.4 million covered only about a quarter of the $1.48 billion investing outflow, so the gap was filled by equity offerings (about $1.6 billion raised across 2014 including Viper) and borrowings. Proved reserves reached 112.8 MMBOE at year-end 2014, up from 63.6 MMBOE, with about 67% oil and 58.9% proved developed. The reserve base is concentrated in one geographic area and a small number of horizons, and 41% of proved reserves are undeveloped. Management also disclosed that it would cut its 2015 rig count and hold the capital budget at $400-450 million, citing the collapse in oil prices from over $105 in June 2014 to below $50 by February 2015. Balance sheet leverage is moderate: long-term debt was $673.5 million, including $450 million of 7.625% senior notes due 2021, against a revolver with $276.5 million of availability. The company is also heavily reliant on Shell Trading (64% of 2014 revenue) and carries full-cost accounting exposure to future ceiling-test write-downs if prices stay low. For investors, the central question is whether the company can sustain returns and production growth with a shrinking drilling program and weaker prices. The filing shows strong 2014 momentum, a clean audit with an unqualified internal-control opinion, and no impairment recorded to date, but it also shows that 2015 economics depend heavily on oil prices and service-cost deflation that the company itself describes as uncertain.
Feb 20, 2015
2013
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2013
Diamondback Energy (FANG) closed 2013 as a fast-growing, oil-weighted independent producer focused entirely on the Permian Basin's Wolfberry play in West Texas. Revenue rose 177% to $208.0 million, driven by average daily production of 7,321 BOE/d (up 149%), with the business roughly 76% oil. Net income swung to $54.6 million from a $36.5 million loss in 2012, though 2013 results included a $31.8 million income tax provision and the 2012 figure was distorted by a one-time $54.1 million deferred tax charge tied to the company's conversion to a C-corporation. Year-end proved reserves reached 63.6 MMBOE (about 67% oil), up roughly 58% from 40.2 MMBOE a year earlier, and the company holds 65,938 net acres, about 99% of which it operates. The balance sheet expanded substantially. Total assets rose to $1.52 billion and stockholders' equity to $845.5 million, funded by two equity offerings in 2013 and a $450 million 7.625% senior notes issuance due 2021. Long-term debt stood at $460 million, with only $10 million drawn on a $225 million borrowing base, and the company's leverage and liquidity position remain comparatively conservative. Management plans a 2014 capital budget of $425–$475 million (a 48% increase) and expects a 2014 borrowing base of $375–$400 million after the pending Martin County acquisition. Key risks for investors include heavy commodity price exposure (hedging covers only part of output, and the company uses full cost accounting, which creates write-down risk if prices fall), concentration in a single basin and a few producing horizons, reliance on two purchasers for 74% of revenue, a large share of undeveloped reserves (about 53% PUD), and continued influence from Wexford (about 22.6% ownership), which is also tied to several related-party service arrangements. The February 2014 agreements to acquire Martin County leasehold for approximately $174 million, with an option to pursue further interests for up to roughly $397 million, would materially expand the acreage base if completed.
Feb 19, 2014
2012-A
Diamondback Energy, Inc. Annual Report (Amendment), Year Ended Dec 31, 2012
Diamondback Energy, Inc.'s (FANG) 2012 Annual Report, filed as an amendment (10-K/A) on April 10, 2013, provides insights into its leadership team and executive compensation structure as it navigated its post-Initial Public Offering (IPO) period. The company has established a strong management team with extensive experience in the oil and gas industry and finance, underscoring a strategic focus on operational expertise and financial stewardship. The compensation philosophy emphasizes attracting and retaining talent through competitive packages, with a significant portion tied to long-term equity incentives to align management's interests with those of shareholders. This approach signals a commitment to sustainable growth and value creation.
Apr 11, 2013
2012
Diamondback Energy, Inc. Annual Report, Year Ended Dec 31, 2012
Diamondback Energy (NASDAQ: FANG) filed its first annual report as a newly public company, covering fiscal 2012, following its October 2012 IPO of 14.4 million shares at $17.50 that raised about $234.1 million net. The company is an independent oil and gas producer focused entirely on the Wolfberry play in the Permian Basin of West Texas, holding 51,603 net acres at year-end 2012 and operating about 99% of that acreage. Production averaged 2,946 BOE/d in 2012, up 78% from 2011, and is roughly 70% oil. Estimated net proved reserves were 40.2 MMBOE at year-end, about 65% oil, with 30.7% proved developed. Revenue rose to $75.0 million from $49.4 million, but the company posted a net loss of $36.5 million, driven by a one-time $54.1 million deferred tax charge tied to the conversion from a pass-through LLC structure at the merger. Operating performance improved meaningfully: income from operations was $17.3 million, Adjusted EBITDA reached $48.2 million (up from $31.9 million), and operating cash flow rose to $49.7 million. Lease operating expense per BOE fell to $15.57 from $17.51. Liquidity looks sound, with $26.4 million of cash, no drawn balance on a $250 million facility with a $135 million borrowing base, and a debt-free position after the IPO proceeds repaid all revolver and subordinated borrowings. The 2013 capital budget of $270 to $300 million, with 37 vertical and 25 horizontal wells planned, will be the key driver of growth. Investors should weigh the company's limited operating history, heavy concentration in a single basin and a few purchasers, reliance on Wexford as its controlling sponsor, and exposure to future hedging and regulatory changes. The filing also highlights a large inventory of potential drilling locations (881 vertical on 40-acre spacing, 1,118 on 20-acre downspacing, and 731 horizontal) and early horizontal results from the Wolfcamp B interval, including the Janey 16H and Kemmer 4209H wells. Management's view is that horizontal drilling could materially raise recovery per section, though these results are still limited and the company has said longer laterals are needed to prove economics.
Mar 1, 2013