The New Horizontal Permian Basin

Joseph Bachmann 504.582.2637 josephb@howardweil.com Philip Stuart 504.582.2554 philips@howardweil.com Brian Corales 504.582.2555 brianc@howardweil.com Blake Fernandez 504.582.2528 blakef@howardweil.com Peter Kissel 504.582.2881 peterk@howardweil.com Holly Stewart 713.393.4512 hollys@howardweil.com David Amoss, CFA 504.582.2638 davida@howardweil.com Blaise Angelico 504.582.2553 blaisea@howardweil.com Alonso Guerra-Garcia 713.393.4511 alonsog@howardweil.com K. Blake Hancock 713.393.4502 kennethh@howardweil.com Richard Roberts 504.582.2560 richardr@howardweil.com Bill Sanchez 713.393.4505 williams@howardweil.com Quick Take: Over the past two years, horizontal activity has ramped in the Permian Basin and is likely to command the lion s share of drilling capital in the coming years as the stacked pay horizons and thick oily reservoirs are proving to have greater potential than originally expected over a larger portion of the basin. Whereas 2013 saw industry establish the potential for horizontal drilling in a variety of pay zones, 2014 could provide added clarity surrounding acreage/operator differentiation. With 233 (54% increase Y/Y) horizontal rigs currently running, the delineation of the Permian could occur in a short time period. The Permian now holds ~27% of the total U.S. rig count and ~20% of the total horizontal rig count. Additionally, unlike other mature onshore oil basins, many smaller or private companies remain in the Permian, and we expect consolidation to heat up throughout 2014. Delaware: The Bone Spring, while more geologically complex than the Wolfcamp, generates some of the highest rates of return in the region and should continue to drive production. Wolfcamp activity remains in the early stages, but results along the state line area and further south in Loving, Reeves, and Ward counties are encouraging and bode well for future industry development. Midland: The southern horizontal Wolfcamp play is in development mode with operators now concentrating on efficiencies and lower costs. Further north in the heart of the Midland Basin, initial results have been very encouraging, but operators are still delineating the areal extent and potential for multiple horizons. Top Picks: Our top Permian Basin picks are CXO, ROSE, FANG, & ATHL. Figure 1: Delaware Leverage Delaware Basin Acreage Positions Independent E&P Operators Company Ticker Acreage Acreage/NEV ($MM) Forest Oil FST 60,250 51.33 Cimarex Energy XEC 437,693 47.75 Matador Resources MTDR 49,000 33.36 Concho Resources CXO 419,556 30.30 Energen Corp. EGN 170,505 23.67 Quicksilver Resources KWK 45,000 20.64 Occidental Petroleum OXY 1,355,000 17.43 Devon Energy DVN 320,000 10.49 Rosetta Resources ROSE 40,000 10.03 Whiting Petroleum WLL 90,000 9.47 Apache Corp. APA 287,000 7.03 Anadarko Petroleum APC 330,000 6.43 EOG Resources EOG 207,000 4.21 Linn Energy LINE 74,000 3.74 ConocoPhillips COP 150,000 1.50 SM Energy SM 2,750 0.37 Source: Company data & Figure 2: Midland Leverage Midland Basin Acreage Positions Independent E&P Operators Company Ticker Acreage Acreage/NEV ($MM) Approach Resources AREX 149,000 159.97 Callon Petroleum CPE 35,000 95.07 Athlon Energy ATHL 109,000 40.17 Pioneer Natural Resources PXD 900,000 39.09 Laredo Petroleum LPI 141,230 33.88 Diamondback Energy FANG 65,000 26.49 Devon Energy DVN 644,000 21.11 SM Energy SM 127,000 16.97 Quicksilver Resources KWK 36,000 16.51 Apache Corp. APA 625,000 15.31 Chesapeake Energy CHK 470,000 12.90 Energen Corp. EGN 87,000 12.08 Concho Resources CXO 155,000 11.19 W&T Offshore WTI 25,370 11.15 Range Resources RRC 100,000 6.15 Occidental Petroleum OXY 410,000 5.27 Linn Energy LINE 90,000 4.55 QEP Resources QEP 27,000 2.85 EOG Resources EOG 113,000 2.30 ConocoPhillips COP 90,000 0.90 Source: Company data & is a division of Scotia Capital (USA) Inc., a member of the Scotiabank group, and represents Scotiabank s energy equities business in the United States. For all relevant disclosures and certifications see Appendix A of this report. 1100 Poydras Street, Suite 3500 New Orleans, LA 70163

Executive Summary Delaware Basin: The more horizontally mature area of the Permian continues to serve as the workhorse and foundational area for horizontal development. Anchored by the prolific Bone Spring, the Delaware has significant growth opportunities emerging through the Wolfcamp play that is rapidly expanding in the southern and central portion of the basin. Continued success in the Wolfcamp zones could significantly increase drilling inventory and lead to more efficient and cost effective development through potential incorporation of multi-well pads and stacked laterals. We believe CXO is the best way for investors to gain direct exposure to the Delaware. Concho is the premier operator in the basin with a proven track record and vast high quality acreage position. In addition, the Company s recently announced 3-year HZ drilling program could double current production providing significant growth opportunities through the drill-bit. While ROSE is not a pure play operator, its recent acquisition should be better defined horizontally this year. The acreage is in close proximity to very good recent well results and with 4 horizontal rigs currently running; ROSE should have a flurry of new wells coming out in 2014. Investors can gain concentrated Delaware exposure in small and mid-cap names such as XEC, EGN, & MTDR. In the large cap space, the primary Delaware operators are APA, APC, DVN, EOG, & OXY. Midland Basin: In 2013, the Midland emerged as a reinvigorated basin capable of generating strong returns similar to those achieved to date in the Delaware. What is even more impressive is the Midland Basin has proven to be more consistent, which should make it conducive for large-scale developments. Operators are shifting development plans away from vertical drilling towards horizontal activity and are testing multiple zones. While we are earlier in the horizontal development life cycle, we see significant opportunity to increase drilling inventory through decreased density spacing and the potential incorporation of stacked lateral development programs. The best way for investors to gain broad exposure to the Midland is through PXD, which has the largest acreage position and is the most active operator in the basin. While PXD is one of the premier operators in the basin, the valuation is still a bit rich versus some of the other Permian operators. In the central portion of the play, our top pure play name is FANG because of the Company s rapidly growing horizontal drilling program that is yielding some of the best results in the basin while consistently decreasing well costs. In the central/northern portion of the play, our top pure play name is ATHL because it offers investors exposure to the Company s recently initiated horizontal program, which we believe could lead to explosive growth if successful. In the southern portion of the play, the top pure play operator is AREX; however, the name has been volatile over the past year, as the Company has transitioned into development mode. While we feel like the name is relatively cheap versus its Midland peers, we believe AREX could continue to experience volatility over the next year due to investor concerns over the lumpy production accompanying development mode. Other small and mid-cap names with meaningful leverage to the Midland include LPI, CPE, LINE/LNCO, CXO, EGN, QEP, SM, & WTI Oilfield Services: While horizontal drilling activity is expected to increase in 2014, the relative distance from the Permian to other major basins (such as the Eagle Ford) should keep supply/demand in balance for most service lines. The switch to horizontal drilling from vertical should benefit the larger land drillers with more AC rigs in the basin, like HP, PTEN, PDS and NBR. For the more service intensive completion and well servicing work, we believe that the large cap diversified companies (HAL, BHI, SLB) will be most successful, with smaller cap more regional players (BAS and KEG) also seeing improvement in the utilization of equipment. Page 2 of 82

Market Activity: 2013 proved to be a highly active period for both capital markets activity and M&A in the Permian. Since May of 2012, there has been ~$8.5 billion of M&A transactions and several notable initial public offerings. Additionally, Permianlevered stocks exhibited tremendous success, which we think could continue in 2014. Looking ahead, we anticipate capital markets activity will remain robust over the coming quarters and would not be surprised to see consolidation in the region via corporate M&A activity. The Permian Basin generates strong returns and offers significant exploration and development opportunities and as such, we continue to favor stocks with direct exposure to the multiple pay horizons present across the basin. Whereas this report focuses primarily on the horizontal development of the Permian Basin, please refer to our previous Permian Basin report (Click Here), which provides a broader general overview of the Permian and its geological characteristics. Figure 3: Permian Basin Core Areas N. Delaware Core Bone Spring HZ Results Coming in 1H14 Central Delaware Core Bone Spring & Wolfcamp W. Midland Core Wolfcamp W. Central Midland Core Wolfcamp & Cline S. Delaware Core 3 rd Bone Spring & Wolfcamp S. Midland Core Wolfcamp Source: & DI Desktop Page 3 of 82

Delaware Basin The Delaware Basin, located on the western flank of the greater Permian Basin, is separated from the Midland Basin by the Central Basin Platform. The Delaware constitutes a roughly 10,000 sq. mi., or 6.4 million acre area extending from the southeastern New Mexico counties of Eddy, Lea, and Chaves southward into the western Texas counties of Culberson, Loving, Reeves, Ward, Pecos, and Jeff Davis. Figure 4 provides a geographical representation of the Delaware and the associated counties as well as the vertical depth of the target Bone Spring formation across the basin. Historically, production in the Delaware Basin has focused on the vertical development of the commingled Wolfbone formation and the Abo/Yeso in the NW Shelf. However, as industry has incorporated horizontal drilling and enhanced fracture stimulation technologies, the majority of activity has shifted to the horizontal development of the 2 nd & 3 rd Bone Spring & Avalon in the northern portion of the basin, the 3 rd Bone Spring and Wolfcamp in the southern portion of the play, and the 3 rd Bone Spring, Abo, and Yeso in the NW Shelf. Of the various pay zones present in the Delaware, the Bone Spring formation has attracted the bulk of industry horizontal activity. However, as activity moves further south, operators are beginning to develop and delineate the deeper Wolfcamp benches. Continued success in the Wolfcamp would be an added positive for future development in the Delaware as many operators have larger prospective acreage positions for the Wolfcamp than for the Bone Spring, which has the potential to significantly increase drilling locations. In addition, continued delineation and development of the Wolfcamp could afford operators the ability to develop the basin using pad drilling and stacked laterals because of the presence of multiple Wolfcamp benches in the southern portion of the play. The following sections highlight the active plays, focusing on changes in well profiles and completion techniques, field results over time, and public company activity. Figure 4: Delaware Basin Bone Spring Vertical Depth Map Source: Wood Mackenzie Page 4 of 82

Bone Spring Formation Characteristics The Bone Spring formation includes the 1 st, 2 nd, & 3 rd Bone Spring sands and similarly named carbonate sections that are generally lumped together with their corresponding sands by public operators. The combined gross column of the Bone Spring sands is ~2,500-3,500 thick, with the formation getting thicker and deeper as it migrates from West to East until it disappears abruptly at the Central Basin Platform. To date, the Bone Spring formation is the most prolific and highly drilled horizontal zone in the Delaware Basin, with operators predominantly targeting the 2 nd & 3 rd Bone Spring in the northern portion of the basin and the deeper 3 rd Bone Spring in the southern portion of the basin. While there is variability in the thickness of the rock and vertical depth of the reservoir as the formation moves from West to East, operators are generally finding the most success in central Eddy & Lea counties, the Texas/New Mexico state line, and western Loving & Ward counties. Well Profiles & Field Results Overview: Because of the geological and stratigraphic variances throughout the basin, there are certain areas that are more prospective than others with varying well results and EURs for the Bone Spring formation. We have examined the changes in well profiles in the play since our last report (Jan. 2012) and compared how results have improved. We also studied where horizontal delineation is focusing as operator activity has increased throughout the Delaware. Figure 5: Bone Spring Production by Date Source: DI Desktop & ** 2013 well data is as of 9/30/13 As identified in Figure 5, which depicts the peak month Bopd from horizontal Bone Spring well results since 2008, there are well-defined hot spots in central Eddy & Lea counties, the state line area and Ward & Loving counties. Additionally, upon examining drilling rig locations and recent well results, we expect operators will attempt to delineate the Bone Spring further into Reeves County west of the Pecos River. The Bone Spring is present in that area, but to date the majority of successful drilling activity has taken place in the Ward County area east of the Pecos River. Page 5 of 82

Production Data: Production throughout the basin has been rapidly increased since horizontal development essentially began in the area in 2008. As has been in the case in the other horizontal unconventional developments, well results and importantly, oil production, have increased as operators enhance their knowledge of the geological formations and discover the optimal spacing and completion techniques. However, cost reductions in the Delaware are more difficult to achieve than other unconventional plays because of the heterogeneous geological structure throughout the Delaware, the deeper vertical presence of the target formations compared with other plays and the lack of infrastructure spending. Well results, as outlined in Figures 6 and 7 indicate how the play has evolved over the past six years, and further confirm the core areas of operations. Figure 6: Horizontal Bone Spring Production by Date Bone Spring W e lls by Ye a r Ye a r** # of W e lls BOEPD* % Oil 2008 24 218 71% 2009 39 275 69% 2010 94 420 52% 2011 215 381 65% 2012 310 486 69% 2013 246 497 71% Source: DI Desktop & *BOEPD data is reflective of the 1 st practical month production levels ** 2013 well data is as of 9/30/13 Figure 7: Horizontal Bone Spring Production by County Bone Spring W e lls by County County W e ll Count BOEPD* % Oil CULBERSON (TX) 15 811 57% EDDY (NM) 590 440 63% LEA (NM) 188 439 83% LOVING (TX) 100 437 60% REEVES (TX) 19 266 69% WARD (TX) 43 457 74% WINKLER (TX) 15 190 83% Source: DI Desktop & *BOEPD data is reflective of the 1 st practical month production levels Well Profiles: Well costs throughout the Delaware have significant variances due to the vertical depth changes from West to East and North to South throughout the basin. Figure 8 identifies our assumptions for the primary Bone Spring operators, Concho Resources and Cimarex Energy, in their respective acreage positions in the Delaware Basin hot spots. The West Texas 3 rd Bone spring area in Western Ward County currently yields the highest IRR at ~87%. This area appears to yield the most prolific wells based on our research in both the Bone Spring and Wolfcamp formation; however, it is important to note that the Ward County area is in the vertically deeper southern portion of the basin, so drilling depths have a significant impact on increased rates and higher drilling and completion costs. The central Eddy & Lea counties area also offers a very attractive return for operators and is by far the most actively drilled area in the Bone Spring due to its high oil content (84%) and repeatable results. The third hot spot, the Culberson and Eddy County /state line area, also offers competitive returns at ~61% with lower costs than the other areas because of the vertical depth of the target Bone Spring formation. While the production in this area contains lower oil content, lower costs and higher production rates enhance returns to competitive levels. Page 6 of 82

One important note about the Bone Spring formation in the Delaware is the lateral length of the horizontal wells. Operators in the Bone Spring generally complete their wells with laterals of ~4,500 as compared with the 7,500 & 10,000 laterals that are gaining popularity in the Midland Basin and have become the norm in more developed unconventional plays. The primary reasons for the shorter laterals are the heterogeneous nature of the Bone Spring and its complexity throughout the basin in addition to acreage lease line restrictions. Figure 8: Delaware Bone Spring Well Profiles Delaware Basin HZ Bone Spring Type Curves Metric W. TX 3rd B.S. Eddy/Lea NM State Line EUR (MBoe) 1,000 630 1,000 30-day IP (Boe/d) 1,000 670 850 % Oil 80% 84% 58% Cost ($mm) $6.5 $6.4 $5.4 Spacing 160 160 160 TVD (ft) 10,000-11,000' 8,000-9,000' <8,000' Lateral (ft) 4,500' 4,500' 4,500' Frac Stages 5-8 5-8 5-8 IRR 87% 73% 61% Source: Company Presentations & Public Company Activity The most active public Bone Spring operators in the Delaware include Anadarko (APC), Cimarex (XEC), Concho (CXO), Devon (DVN), Energen (EGN) and EOG Resources (EOG). Additionally, several private operators are active participants, including Mewbourne, Yates Petroleum, Bopco, and Riki Exploration. In addition to these operators, we expect considerable increases in development from the large independents and majors who already have substantial lease positions, including Apache (APA), BHP Billiton (BHP), Chevron (CVX), Conoco (COP), Occidental (OXY), and Shell (RDS). We believe the Bone Spring and Wolfcamp in the Delaware are onshore plays that could continue to compete for capital from large independents and majors due to its economic viability in different commodity price environments. We believe OXY in particular presents one of the most attractive names to grow horizontal production in the Delaware. The Company maintains the largest legacy acreage position with over 1.3MM acres, but to date has remained more focused on its enhanced oil recovery program and vertical drilling. Additionally, we believe the area could experience consolidation in the coming years as other larger operators look to add scale in their development of the Permian. Figure 9 depicts horizontal Bone Spring activity by operator. Page 7 of 82

Figure 9: Bone Spring HZ Production by Operator Source: DI Desktop & Many operators effectively divide the Delaware Basin into northern and southern sections just below the state line hot spot and show it extending down through Loving, Ward, Culberson, Reeves, and Pecos counties. As drilling continues into the southern portion, operators focus primarily on the 3 rd Bone Spring and the emerging Wolfcamp benches. The Wolfcamp has seen a significant ramp in activity recently and is beginning to supplant the Bone Spring as the primary target. However, while the 3 rd Bone Spring formation in the southern portion of the narrow window encompassing western Loving and Ward counties still produces some of the most economic results in the basin, there are not as many prospective drilling locations compared with the Wolfcamp. Figure 10: Southern Delaware 3 rd Bone Spring Core Area Source: Energen Resources Company presentation Page 8 of 82

Energen and Cimarex are currently the leading Bone Spring operators in the southern portion of the play followed by Anadarko and Shell with the majority targeting the 3 rd Bone Spring. Certain areas in the 3 rd Bone Spring produce better well economics than the 2 nd Bone Spring in the North albeit with higher costs at deeper formation depths. For example, Cimarex drilled 33 wells in 2013 in the Ward County area with an average 30- day IP rate of 1,000 Boepd (~80% oil). Cimarex plans to continue drill the formation due to its attractive returns and the Company s significant acreage position in the area. XEC will also remain active in the other two Bone Spring areas while increasing its activity in the Wolfcamp formation in the southern portion of the basin. The major catalyst for future development in the coming months for operators in the 3 rd Bone Spring is the delineation of the play west of the Pecos River into Reeves County. Recently operators are having more success in the Wolfcamp formation in Reeves County, but we expect operators to continue to test and develop the 3 rd Bone Spring in the area as well. In general, we believe the Bone Spring formation still has plenty of room to run in the long-term and anticipate that further delineation to the west could serve as a primary driver to expand the play boundaries. The different Bone Spring plays offer some of the best unconventional returns in the onshore U.S. and we believe it will continue to be one of the most actively drilled plays in the Permian Basin. Delaware Basin Wolfcamp Formation Characteristics Overview: While the Wolfcamp formation is present across the entire Permian region, the following information focuses on activity within the Delaware sub-basin. The depth trend of the Wolfcamp is similar to the rest of the Delaware stratigraphy, with an asymmetric eastern bias and a gradual upward slope as the basin stretches westward. The Delaware Wolfcamp is largely a horizontal oil play with the exception of some commingled Wolfbone verticals with a median hydrocarbon mix similar to the Bone Spring at 60% crude, 20% wet gas and 20% dry gas. Most of the current activity targets the oilier Upper Wolfcamp rather than the significantly more gas-prone and mature Lower Wolfcamp. The upper sections comprise a roughly 1,000 gross interval that sits at depths of 10,000 12,000 (though the Wolfbone vertical wells are drilled to 11,000 12,500 ). In aggregate, the Wolfcamp interval is ~2,000 thick. Well Profiles & Field Results Over the past two years, there has been an emergence of horizontal Wolfcamp drilling primarily in the state line area and southern portion of the basin with most operators targeting the upper Wolfcamp A bench. The core area of the Wolfcamp in the Delaware lies in the Ward, Loving, and eastern Reeves County areas with the best results coming from western Ward County. Operators are predominantly drilling the Wolfcamp C & D in the shallower western portion of the play around the state line area. While it is still early in Wolfcamp development in the Delaware, operators are delineating acreage positions and estimating resource potential. Based on information gathered from current operators and assuming 45MMBoe OOIP per section in each zone and an 8% recovery factor, the potential resource addition for a successful Wolfcamp development on 10,000 acres is ~56MMBoe per zone or 100 drilling locations based on a 560MBoe type curve. Furthermore, Figure 11 highlights Delaware Wolfcamp wells to date by age and relative size. Page 9 of 82

Figure 11: Delaware Wolfcamp Wells by Date Source: DI Desktop & ** 2013 well data is as of 9/30/13 Well Profiles: Well profiles for the different Wolfcamp benches vary across the play with the Wolfcamp A bench in the core Ward County area delivering much higher oil content than the Wolfcamp C & D benches in the state line area. The Ward County area, and to a lesser extent Reeves and Loving, appear to offer the best economics for the Wolfcamp in the Delaware and we expect extensive drilling to continue in these areas. Several operators, namely Cimarex and Chevron, which recently formed a JV in the state line area, are experimenting with Wolfcamp A drilling hoping to achieve an oilier production mix than the Wolfcamp C & D wells that have been the main target to date. Outside of the two core areas, some private operators have had limited success drilling the Wolfcamp in the NW shelf area, and we are beginning to see activity increase in SW Reeves County down into Pecos County. Operators have experienced more success drilling the Wolfcamp than the Bone Spring in the area west of the Pecos River in Reeves County. We see this as an encouraging sign for the play as operators will look to continue delineating acreage positions further west and south. Figure 12: Delaware Wolfcamp Production by Date Delaware Basin HZ Wolfcamp Type Curves Metric WC A Ward WC C&D State Line EUR (MBoe) 900 833 30-day IP (Boe/d) 925 1,033 % Oil 63% 28% Cost ($mm) $7.3 $7.3 Spacing 160 160 TVD (ft) 8,000-10,000' 8,000-10,000' Lateral (ft) 4,500' 4,500' Frac Stages 8-10 8-10 IRR 43% 21% Source: Company Presentations & Page 10 of 82

Figure 13: Delaware Wolfcamp Production by Year De la wa re W olfca mp W e lls by County Ye a r** W e ll Count BOEPD* % Oil 2008 41 249 67% 2009 13 313 79% 2010 58 506 73% 2011 95 434 68% 2012 111 580 64% 2013 63 480 64% Source: DI Desktop & *BOEPD data is reflective of the 1 st practical month production levels ** 2013 well data is as of 9/30/13 Public Company Activity Exploration and development activity in the Wolfcamp has largely been driven by several large independents and majors, with the majority of wells targeting the Wolfcamp A in Ward, Loving, and Reeves counties. The most active operators to date have been Anadarko, BHP Billiton, Cimarex, Concho, Shell, and Devon. Other operators in the play who have significant prospective acreage positions, but have tested limited amount of Wolfcamp wells include: Chevron, Energen, EOG Resources, Occidental, Rosetta, Whiting and Matador. Figure 14 depicts operator activity in the Delaware Wolfcamp. Figure 14: Top Delaware Wolfcamp Operators Source: DI Desktop & Anadarko, Shell, and Cimarex have arguably the best acreage positions for the Wolfcamp A in the core of the play in western Ward County, where well results are considerably higher than neighboring counties (See Figure 15), achieving the highest peak oil rates. We estimate wells generate rates of return in excess of 40%. Anadarko recently commented during its 3Q13 earnings call that the Company is currently running 6 rigs in the Ward and Loving County area targeting the Wolfcamp A and achieved 24-hr. IP rates over 1,000 Boepd with a >70% oil cut on its last 7 wells. Cimarex has also recently provided some 30-day rates from its wells in eastern Reeves County. XEC announced two Wolfcamp A tests with >900 Boepd average 30-day rates and a 10,000 lateral test which achieved a 30- day rate of 1,816 Boepd (56% oil). Page 11 of 82

Figure 15: Delaware Wolfcamp Production by County De la wa re W olfca mp W e lls by County County W e ll Count BOEPD* % Oil Culberson (TX) 30 638 35% Eddy (NM) 77 407 66% Lea (NM) 4 37 81% Loving (TX) 45 418 68% Reeves (TX) 69 278 65% Ward (TX) 164 579 76% Source: DI Desktop & *BOEPD data is reflective of the 1 st practical month production levels One trend that is clear to see in the play early on is that production mix tends to be much gassier as operators move west and north from the Ward County core area. BHP Billiton has been one of the most active operators delineating their acreage position out to the north and west of Ward County, as is shown in Figure 14, Page 11. It is still very early in the Wolfcamp development, but thus far, we have not seen any operators drill the Wolfcamp to the west or south of BHP s most recent wells. In the more northern section of the Wolfcamp window, the Chevron and Cimarex JV will be very important to monitor moving forward. Other operators including BHP, Concho, and Devon are also planning to continue to drill the state line area testing both the Wolfcamp A and the Wolfcamp C & D. Successful Wolfcamp A tests could be a real boon for the play as it could open several intervals that operators could develop using stacked lateral multi-well pads, which would decrease costs and improve efficiencies. The Wolfcamp formation is likely to drive the future growth of the Delaware along with the Bone Spring. We see these two plays as the core of the Delaware development moving forward with the Wolfcamp providing the strongest growth opportunities because it is still in the early stages of development when compared with the Bone Spring. As operators continue to delineate acreage positions and test, the Wolfcamp benches in different locations we feel valuations in the Delaware and potentially M&A activity could increase as larger operators look to expand their footprint in the play. Page 12 of 82

Midland Basin The Midland Basin is located to the east of the Central Basin Platform and runs north-south from southern Lamb and Hale counties to northern Crockett County. The basin has a long history of vertical oil exploration and development dating back to the 1940s. More recently, and similar to the development of the Delaware, operators have integrated advanced drilling and completion technologies into vertical multi-zone completions and horizontal applications. As such, activity in the Midland Basin has increased considerably over the past few years, unlocking additional hydrocarbon volumes and opportunities for greenfield activities in additional formations. Historically, the Spraberry was the most frequent target for single stage completions, but with technological advances, including the ability to drill deeper and more effective fracking techniques, the Wolfcamp zone has been added as a primary target for horizontal development. The following sections examine the development of horizontal drilling in the Midland with the central focus being on the Wolfcamp in the southern and central portions of the basin. Figure 16: Midland Basin Overview Source: Concho Resources Company Presentation Page 13 of 82

Formation Focus: Midland Basin Wolfcamp Formation Characteristics The Wolfcamp formation is present across the entire Permian Basin; however, the Midland Basin appears to offer the largest potential area for development. The Wolfcamp formation in the Midland Basin extends from the NW in central Dawson and Gaines counties down to Crockett County in the SE. Horizontally the Wolfcamp begins in eastern Andrews, Ector, and Crane and extends eastward into Howard County on down. The formation is ~12,000 in the deepest section in the central portion of the basin and gradually becomes shallower as the trend moves to the southern extension in Crockett County, where the Wolfcamp formation is less than 7,000 in depth. Furthermore, as the trend moves towards the Eastern Shelf the formation depth decreases to around 4,000. Figure 17 (map below) depicts the vertical depth of the target Wolfcamp formation across the basin, displaying the current location of horizontal operating rigs as of November 2013 and identifies the completed horizontal wells to date. The southern portion of the Midland has historically hosted the majority of horizontal industry activity. However, operators are quickly moving towards the central and northern areas. The primary effect of the depth of the formation in the more central/northern portion of the basin is higher pressure in the target formation, which yields stronger IP rates as well as slightly higher oil content. Additionally, while determining the thickness of the Wolfcamp formation throughout the basin can be challenging, recent operator activity suggests the formation may be thicker in central and western Midland and Upton counties as well as eastern Reagan and Glasscock counties. Figure 17: Target Wolfcamp Formation Midland Basin Activity Source: Callon Petroleum Company Page 14 of 82

Area Overview: Southern Midland Basin Wolfcamp Well Profiles & Field Characteristics Figure 18: Southern Midland Wolfcamp Wells by Date Source: DI Desktop & ** 2013 well data is as of 9/30/13 Overview: Horizontal drilling in the southern portion of the Midland Basin has focused primarily in northern Crockett, Irion, Upton and Reagan counties. The preponderance of wells drilled to date have targeted the Wolfcamp B formation with some operators also testing the Wolfcamp A and C. The Wolfcamp D bench, or Cline Shale as it is often referred to, is primarily targeted further north into Sterling and Glasscock counties. To date there has been limited drilling of the D bench in the southern portion of the basin. Additionally, the target Wolfcamp formation in the southern portion of the play appears to be ~400-1,000 thick with estimates for each bench ranging from ~200-400 according to multiple operators as Figure 19 depicts. Page 15 of 82

Figure 19: Southern Midland Wolfcamp Formation Thickness Source: Approach Resources Company Presentation Given the shallower nature of the Wolfcamp in the Southern Midland Basin, drilling and completion costs are notably less. As of 3Q13, we are seeing operators such as Approach Resources, achieve drilling costs as low as ~$5.4 million per well, down from $6.7 million. Conversely, the primary drawbacks to the southern portion of the play are the lack of reservoir pressure and slightly lower oil content. The lack of pressure compared with the more northern counties decreases the IP rates of the wells; however, the returns are not vastly different between the different areas due to lower well costs and lower decline rates in the southern portion of the basin. Figure 20: Southern Midland Wolfcamp Production by County Southe rn Midla nd W olfca mp W e lls County W e ll Count BOEPD* % Oil CRANE (TX) 6 213 71% CROCKETT (TX) 61 233 72% IRION (TX) 88 379 76% REAGAN (TX) 35 269 85% SCHLEICHER (TX) 4 154 65% UPTON (TX) 28 359 63% Source: DI Desktop & *BOEPD data is reflective of the 1 st practical month production levels Page 16 of 82

Well Profiles: Well profiles in the southern portion of the Midland have significant variation as the trend moves from the shallower southern portion of the play around the Crockett County line up to the deeper portion of the play in northern Upton and Reagan counties. Operators are primarily targeting laterals of ~7,500-8,500 with some beginning to experiment with longer laterals up to 10,000 and multi-well pad drilling where leasing units afford the opportunity. Figure 21 outlines our current well profile assumptions for the Wolfcamp B in northern Crockett and the Wolfcamp A zone in northern Reagan. In northern Crockett County, rates of return are estimated to be ~37%, which is aided by existing infrastructure that helps reduce costs. Further north into the deeper portion of the play in Reagan and Upton counties, operators are achieving larger IP rates in wells targeting the A, B, and C benches of the Wolfcamp. Our Wolfcamp A type curve projects a 47% rate of return. Figure 21: Southern Midland Basin Wolfcamp Well Profiles Southern Midland Basin HZ Wolfcamp Well Profiles Metric WC "B" N. Crockett Co. WC "A" N. Reagan County EUR (MBoe) 450 925 30-day IP (Boe/d) 550 832 Oil % 58% 57% Cost ($mm) $5.4 $7.5 Spacing 120 160 TVD (ft) 5,900-6,300' 7,200-7,600' Lateral (ft) 7,500' 7,500 Frac Stages 28+ 19.3 IRR 37% 47% Source: Company Presentations & Pad drilling and multi-well stacked laterals should help fuel the future development of the Wolfcamp in the southern Midland by helping to reduce costs and increase efficiencies. The stacked nature of the Wolfcamp benches in the Midland Basin creates an optimal opportunity to exploit the benefits of the more efficient development. Industry has ample rig/service supply to support the increase in pad drilling and is likely to head more in this direction. As operators such as Approach Resources move into full development mode in the play, stacked laterals targeting the multiple Wolfcamp benches could serve to drive down costs and enhance returns in the play. We expect to see continued development via pad drilling throughout the southern Midland and into the central and northern Midland Basin once acreage held and operators have better understanding of the different zones throughout their acreage. Approach (AREX), Pioneer (PXD), Apache (APA), and Laredo (LPI) are the primary operators spear heading stacked lateral pad drilling in the southern portion of the basin. Page 17 of 82

Figure 22: Midland Basin Stacked Lateral Source: Laredo Petroleum Analyst Day Presentation Public Company Activity Activity in the southern portion of the Midland Basin is primarily led by Apache (APA), Approach (AREX), Devon (DVN), EOG Resources (EOG), Laredo (LPI), and Pioneer (PXD). Additional independents public operators include Callon (CPE), Diamondback (FANG), and BHP Billiton (BHP). Apache is currently running 9 rigs to drill ~93 wells in 2013 and PXD/Sinochem are running 8 rigs to drill ~100 wells for the year and are the most active operators in the play. Furthermore, AREX has the most leverage to the southern portion of the Midland with all of its current and projected drilling currently taking place in this area. AREX, which focuses its operations in northern Crockett County, is currently running 3 HZ rigs to drill ~40 HZ Wolfcamp wells in 2013. Additionally AREX is one of the first companies to enter into full development mode in the play reaping the rewards of significant infrastructure spending that is allowing the Company to achieve some of the lowest D&C costs in the basin at $5.4MM/well in 3Q13. We expect Apache, Pioneer, Approach, and Laredo to continue leading the way in terms of development of the southern Midland into 2014. Pioneer s current drilling plans in its JV will allow the Company to drill ~115 Wolfcamp wells while utilizing 8 horizontal drilling rigs. The current drilling plan will focus two thirds of projected drilling in the Wolfcamp B with laterals averaging 9,400 and a large portion of the drilling program focusing on pad drilling. LPI s 2014 drilling should focus primarily on multi-well pad drilling both in the southern and central portion of the Midland Basin. APA & AREX have yet to release their 2014 Southern Midland Basin drilling programs; however, it is likely to consist of developmental drilling in the three upper Wolfcamp benches using stacked laterals and potentially some D bench tests in northern Reagan and Upton counties. Page 18 of 82

Figure 23: Sothern Midland Wolfcamp Primary Operators Source: DI Desktop & Crockett and Irion counties represent the most heavily drilled areas in the Southern Midland Basin. Laredo has some of the best acreage in the play in NE Reagan County with a sizeable contiguous acreage block. This area has generated some of the largest wells to date, with Laredo averaging a 30-day IP rate of ~885 Boepd on its first 25 Reagan County Wolfcamp wells with the majority of those wells targeting the Wolfcamp A. Additionally, Pioneer in southern Reagan, Apache & EOG in the Crockett/Iron counties line, and AREX in northern Crockett have large contiguous acreage positions that have yielded very competitive economics. Emerging Trends: As was previously mentioned, multi-well pad development with the potential for stacked lateral development ranks as the leading emerging trend in the basin. AREX, PXD, APA, and LPI are the most active operators that are increasing multi-well pad development. AREX s aforementioned infrastructure improvements should also allow the Company to ramp pad drilling in an effective manner in 2014 focusing a meaningful portion of drilling on stacked laterals targeting the A, B, & C benches of the Wolfcamp. Pioneer plans to continue to run its 8 rig HZ program in 2014 and utilize 3 well pads for most of the program targeting all four Wolfcamp benches. Additionally we expect Apache to continue running at least 9 HZ rigs in the play and like the other two operators, we believe they will also focus on pad drilling, specifically in Irion County where the Company is in full development mode. LPI also recently announced that their 2014 drilling program would consist of 60 laterals utilizing 20 multi-well pads targeting various zones. However, a significant portion of these wells will be drilled in the central portion of the basin in Glasscock County, as a meaningful portion their acreage expands beyond Reagan County. Moreover, Laredo recently announced its first 3 well pad in northern Reagan County that achieved a 3-stream 24-hour IP of 3,778 Boepd targeting the Upper, Middle, & Lower Wolfcamp. The Laredo result is one of the first multi-well stacked laterals specifically announced by an operator in the play to date. Page 19 of 82

Figure 24: Southern Midland Basin Acreage Positions Source: Approach Resources Company Presentation The impact of pad drilling should have a significant impact on future drilling plans for the previously mentioned operators, as well as others in the southern portion of the play. The reason why operators are beginning to enter full development mode in the southern portion of the play compared to the more northern counties is twofold: the first being that there have been more wells drilled in this portion of the play and second, operators have less fragmented acreage positions. These contiguous acreage blocks, as depicted in Figure 24, allow operators to spend capital on infrastructure improvements that help drive down costs. Pad drilling does create a more lumpy production profile but the improved efficiency and economics trump these variances in production. To date a large portion of the wells recorded on the Texas RRC have produced very impressive IP rates, which has driven up expectations for the Midland, more particularly in the central portion of the basin. A large portion of these wells drilled to date are considered virgin wells as they are being drilled in very under developed horizontal areas leading to higher IP rates because of increased pressure and lack of reservoir drainage. However, we expect these well results will begin to revert closer to their type curves once operators start to drill multiple well pads. We believe the main reasons for the reversion to be the density of the wells on the acreage position, which will lower reservoir pressure, and the cumulative draining of the reservoir from the nearby wells. The southern portion of the Midland Basin has experienced more horizontal drilling than the more northern counties. As operators begin to rapidly increase activity in the central and northern portion of the Midland, we believe the southern portion of the play could begin to become somewhat overlooked by investors. However, this portion of the play should continue to yield very economic results and could provide investors some untapped value with companies operating in these areas. The results coming out of the southern portion of the play are not likely to match the sexy IP rates or potential returns of those in the more northern counties. However, the southern portion of the basin should continue to deliver very economic returns overtime as costs continue to trend downward and takeaway capacity rapidly increases. Page 20 of 82

Area Overview: Central Midland Basin The Heart of the Midland The Central Midland Basin, outlined in Figure 25, has a long history of drilling for oil with production dating pre-1950, but horizontal drilling is currently re-invigorating the play. While horizontal data points are still in the early stages in the region. Initial results have been very prolific in multiple pay horizons in the Wolfcamp. Operators are now testing the Spraberry zones horizontally as well. The play is developing very rapidly with a potentially staggering inventory emerging, and public operator stock prices have been top performers in 2013. Figure 25: Central Midland Basin Region General Area of Central Midland Basin Source: While we are in the early innings of the region s horizontal evaluation, the basin s history of vertical drilling is a major asset in the development of the horizontal play. Vertical well logs are plentiful in the region, providing more initial data to work with versus other emerging plays, and the basin s operators are benefitting from high quality regional reservoir mapping. This historical data should allow operators to move into full-scale development mode quicker than other comparable play maturity cycles, assuming infrastructure capacity is available to accommodate the ramp in production. We estimate the region we define as the Central Midland Basin shown in the map above spans ~3,600 sq. miles. In terms of stratigraphy, this region s primary horizontal target zone is the thick Wolfcamp. This zone thins in the middle or deepest part of the basin, becoming gradually thicker to the east and quickly thicker to the west as shown in the cross-section below. The Spraberry, possibly a shallower second horizontal target zone, is consistent in the middle of the basin. In total, the Central Midland Basin could have up to 7 prospective zones including 4 Wolfcamp zones, Lower and Middle Spraberry zones, and the Clearfork. Page 21 of 82

Figure 26: Midland Basin Stratigraphic Map Source: Pioneer Company Presentation The Central Midland Basin has historically produced from vertical wells, which recently have reached deeper and commingled production, primarily from the Spraberry and Wolfcamp zones. Over the past several years, even deeper zones have contributed including the Strawn, Atoka, and Mississippian in certain areas. As the focus has now shifted to horizontal exploration and development, the primary initial target is the thick Wolfcamp section with operators also beginning to test horizontal potential in the Spraberry zones such as the Jo Mill. The general stratigraphy of the basin is shown in Figure 27. Figure 27: Midland Basin Stratigraphy Source: Pioneer Company Presentation Page 22 of 82

Wolfcamp Formation Characteristics The Wolfcamp zone in the Midland Basin ~1,500 to 2,500 and has attractive geologic characteristics shown in the following table. Primarily, the reservoir consists of Permian age organic shales with average net-to-gross pay of ~60%. Average porosity is 6% with average TOC ~5.4%. The stacked pays yield an immense OOIP per section, which compares favorably with other onshore oil basins. According to Pioneer Natural Resources, the OOIP per section for the overall Wolfcamp Shale in the Midland Basin is 80 to 220 MMBo per section. The basin s crude is an attractive 40-43 degree API gravity with associated high-btu gas. In total, the Midland Basin has been estimated to contain 50 BBoe of recoverable resource from the Wolfcamp A, B, and D plus the Jo Mill with further upside from the additional Spraberry zones, Strawn, Atoka, etc. Figure 28: Midland Basin Wolfcamp Reservoir Characteristics Source: Laredo Petroleum Company Presentation Early Horizontal Wolfcamp Drilling Data While the horizontal exploration and development in the Midland Basin began in earnest in the southern extent of the region, operators have quickly moved further north, and with even better initial results. From what we know now, the Central Midland Basin may provide the best and most consistent horizontal well returns in the play, although we do not fully know the areal extent and prospectivity for multiple zones. Figure 29 shows selected horizontal wells in multiple Wolfcamp zones, which depict the early geographic concentration and prolific results. Page 23 of 82

Figure 29: Selected Horizontal Wolfcamp Wells Source: Company reports and presentations The history and evolution of drilling in this part of the basin yields important information about horizontal prospectivity and the future potential of the play. Until recently, vertical wells targeted the Spraberry with the completion stage count gradually increasing over time. The Wolfcamp was not a primary target in vertical wells until the past decade when operators began to understand the potential value from commingling the Wolfcamp with the Spraberry zones. These recent deeper vertical wells were drilled in a circular fashion around the basin, as shown in the next map, likely because this was the area with the greatest combination potential from the Wolfcamp and the Spraberry. This drilling pattern likely has three important consequences: Wolfcamp locations within the ring of drilling are likely not to have material historic production from the zone Operators have less Wolfcamp well control within the ring The Wolfcamp zone could have different characteristics in this area, yielding different inventory assumptions While there are not many active permits to test this region horizontally, we hypothesize that the wells could be very prolific due to the more-virgin nature of the Wolfcamp reservoir, although the total well inventory is unknown. PXD plans to drill the region with a couple of wells in 2014. Page 24 of 82

Figure 30: Midland Basin Drilling History Lack of historical Wolfcamp well penetrations Source: IHS, Pioneer presentation Horizontal Permitting Permitting has accelerated in the Central Midland Basin as operators ramp activity testing multiple zones, spacing assumptions, drilling and completion design, etc. Active horizontal permits since 2010 are shown in the following map with most recent rig locations. PXD has the most horizontal permits followed by APA, LPI, and FANG. Figure 31: Horizontal Permits Since 2010 Source: DI Desktop & Page 25 of 82

Early Well Profiles & Field Characteristics While it is still early in the evaluation phase and important characteristics such as areal extent, optimal spacing, and total horizontal inventory remain unknown, we have enough data to begin to make type well and economic assumptions. We list early public operator assumptions in Figure 32, and it is apparent that these assumptions are trending towards similar outcomes. Average EURs in the Wolfcamp A and B range from 600 to 925 MBoe. There is more conflicting data about the Wolfcamp C and D (Cline) some of this may arise from the fact that different operators classify the zones differently; i. e. one operator s Lower Wolfcamp may include parts of another operator s Wolfcamp B, C, and/or D. Some operators separate the Wolfcamp D from the Cline shale while others use the two names synonymously. Figure 32: Horizontal Wolfcamp Well Profiles Central Midland Basin HZ Wolfcamp Well Profiles Metric LPI Cline LPI Upper WC FANG WC B PXD WC A&B EUR (MBoe) 796 925 600 800 30-day IP (Boe/d) 889 832 700 900 Oil % 47% 57% 71% 73% Cost ($mm) $8.4 $7.5 $7.3 $8.0 Spacing 160 160 160 160 TVD (ft) 9,000-9,500' 7,200-7,600 7,800-8,100 7,000-7,800 Lateral (ft) 7,500 7,500 7,500 7,000 Frac Stages 26 19 28 30 IRR 33% 46% 35% 60% Source: Company presentations & Well Evolution and Efficiencies As much of the horizontal drilling so far in the Central Midland Basin has been exploration, we have not yet seen what a true development program may look like. However, because of the legacy of drilling in the region and very good log and core-driven mapping, we expect operators will quickly move into a more optimal development mode. Currently, the Wolfcamp has seen longer laterals with operator consensus around 7,000 to 7,500 lateral lengths. While this may continue to get longer, we think this is a reasonably fair estimate of average lateral length going forward, possibly with some longer laterals mixed in where lease parameters allow. Operators in the region are also moving into more pad drilling. Currently, 2-well pads have become more popular, and we expect the pad size to increase to 3-4 wells per pad in 2014. Pad drilling allows for greater efficiency although results in lumpier production, especially at the onset. LPI estimates efficiency gains of ~40 days for a 4-well pad (10 days per well vs. individual drilling). Because of the potential benefit to operators, the higher spec rigs with better walking/skidding capabilities should continue to gain market share from lower spec rig classes. As time goes on, the batch drilling concept will likely become the norm with operators trying to reduce mobilization times and using common drilling fluid systems between wells. Generally accepted spacing assumptions are 120-160 acre spacing equivalents per zone (660 lateral spacing), although operators in the more southern part of the Midland Basin are now testing much tighter spacing. We expect that this trend will be similar for the Central Midland Basin, and optimal spacing levels could be better known by the early/mid 2015. Page 26 of 82

On the completion side, we expect central Midland horizontal wells will be able to take advantage of some of the recent innovation in other oily shale plays. We are already seeing operators begin to switch from premium proppants to sand where they do not see a production uplift. The average completion is increasing in number of stages with ~250 per stage now popular. Proppant amounts are also on the rise with some operators pumping 250,000 pounds per stage. Perf clusters are becoming tighter with most operators using the plug and perf method. Hybrid or slick-water fracs are most common, and zipper fracs are showing positive initial results. Upcoming Important Data In 2014, we expect horizontal drilling activity in the Central Midland Basin to increase dramatically. Operators are ramping up rig counts in the region, and by the end of 2014, it is likely that the areal extent and core regions by section are much better known. In terms of the meaningful data we are keeping an eye on, the following well results could be forthcoming: ATHL 3 Wolfcamp A wells in Howard County (1H14) could extend the geographic boundary of positive well results to the east and north FANG stacked Wolfcamp B/Lower Spraberry laterals (1Q14) PXD additional Spraberry wells (1Q14) PXD wells further in the circular area where the least Wolfcamp data exists (1Q14) SM wells in Andrews County Other Zone Evaluation and Potential The Spraberry and Clearfork sections, both shallower than the Wolfcamp, are currently being evaluated as additional horizontal targets. In addition, deeper zones such as the Strawn, Atoka, or Mississippian could provide future upside, although the depths and higher well costs increase the exploration risk. To date, the Spraberry has been tested horizontally with promising results considering the lower well cost. IP rates have ranged from ~400 to ~700 Boepd with laterals from 2,500 to 5,000. We expect considerably more data to emerge about Spraberry prospectivity in 2014, with the best areas likely in the central part of the Midland Basin (east to west). The Clearfork is emerging as a potential target zone with limited horizontal data to date. We expect that this zone will not be tested in significant scale until late 2014/2015. Like the Wolfcamp, the classification of the different benches within the Spraberry is not clear-cut and varies from operator to operator. The lower Spraberry (or Jo Mill) has seen the majority of the activity so far with PXD, and FANG leading the effort. While we do not spend much time in this report evaluating the potential of non-wolfcamp zones, this could add additional inventory, and we should know more about the prospectivity over the next 12 months. Public Company Activity Independents dominate the operator activity in the Central Midland Basin thus far with Pioneer Natural Resources having the largest acreage position in the region. Additional active public operators with acreage in this region include Laredo Petroleum (LPI), Diamondback Energy (FANG), Apache (APA), Athlon Energy (ATHL), Energen Resources (EGN), SM Energy (SM), Concho Resources (CXO), Callon Petroleum (CPE), LINN Energy (LINE), and Occidental Petroleum (OXY). The area we have defined as Central Midland Basin houses a whopping 160 total rigs, of which 58 are Page 27 of 82

horizontal. Pioneer is running the most rigs currently with 9 vertical rigs and 10 horizontal rigs. Apache and Laredo are the second and third most active operators in this area of the basin. We expect these same companies to continue to lead the horizontal exploration and development in the region for the next several years, followed by a period of consolidation once the ultimate inventory and economic value of the resource is better known. Figure 33: Central Midland Basin Drilling Rig Activity Source: Drilling Info Public Compa ny T ota l R igs PXD 19 10 APA 14 7 LPI 11 6 ATHL 9 1 CVX 9 9 OXY 9 5 CXO 7 3 FANG 6 5 EGN 6 3 DVN 3 1 CPE 2 2 COP 2 2 SM 2 2 EOG 1 1 W&T 1 0 H Z R igs Central Midland Basin Summary Findings Based on the analysis we have completed to date, the Central Midland Basin is beginning to take shape in terms of regional horizontal prospectivity. Activity in the region is accelerating rapidly, and we should have a more complete view of the play by the end of 2014, including full evaluation of multiple Wolfcamp zone potential, optimal spacing/d&c methodology, and an initial outline of Spraberry and Clearfork potential. In general, the core Wolfcamp areas within the Central Midland Basin to date look to be the eastern and western extents of the play. On the western side, the area from the bottom of Midland County to the top of Martin County has seen prolific wells in multiple benches. On the eastern extent, the east half of Glasscock and Reagan counties has also seen very good results in all four Wolfcamp benches. Two areas we are watching closely in 2014 include the four-way intersection of Midland, Glasscock, Upton, and Reagan counties where we have the least amount of data on the Wolfcamp due to historical drilling patterns. The Wolfcamp section could be untapped in this region although we do not know the inventory implications. Second, we expect near-term results from Howard County, which we will compare to the rest of the play. Also, the Spraberry should see an increase in exploration activity in 2014 and could provide even greater inventory. Drilling and completion methods should become more efficient in 2014, leading to lower costs, better efficiencies, and faster drilling times. At the end of the day, the results to date indicate that this region could prove to be one of the best onshore oil plays in the U.S. Page 28 of 82

02/04/11 04/04/11 06/04/11 08/04/11 10/04/11 12/04/11 02/04/12 04/04/12 06/04/12 08/04/12 10/04/12 12/04/12 02/04/13 04/04/13 06/04/13 08/04/13 10/04/13 12/04/13 January 27, 2014 Figure 34: Central Midland Basin Positive Initial Results from Wolfcamp A, B, & D Additional tests forthcoming Positive initial results from Wolfcamp A, B, C, & D Not much Wolfcamp data to date, testing upcoming Source: Oilfield Services Overview Rig Count The most elemental method of constructing a view of the Permian from a service standpoint is to first look at the rig count and mix of rigs working. Since the beginning of 2011, the Permian rig count has grown more than 25% (Figure 35), and now makes up roughly 27% of the total U.S. rig count. The most meaningful change during this period though has been the switching from vertical drilling to horizontal drilling with the horizontal rig count growing over 250% from this point. Figure 35: Permian Rig Count 600 500 400 300 200 100 0 Total Horizontal Source: Baker Hughes Rig Count Page 29 of 82

02/04/11 04/04/11 06/04/11 08/04/11 10/04/11 12/04/11 02/04/12 04/04/12 06/04/12 08/04/12 10/04/12 12/04/12 02/04/13 04/04/13 06/04/13 08/04/13 10/04/13 12/04/13 January 27, 2014 Figure 36: HZ Rig Count as Percent of Total 60% 50% 40% 30% 20% 10% 0% Source: Baker Hughes Rig Count As the horizontal rig count continues to grow, we would expect to see the service intensity continue to increase as well. While an increase in activity is always welcomed, the flip side for current market participants is that this uptick in horizontal drilling may also attract more supply and greater competition, putting additional pressure on pricing and/or utilization. We would note that it does not seem that this greater competition level has materialized yet. With the Eagle Ford being so close geographically, there has been some equipment moving to the Permian to help maintain utilization, but there has not been a mass migration to the Permian from other basins or the appearance of new entrants en masse. We suspect the competitive landscape in the Permian though is greater than in the Bakken, for example, on the magnitude of ~3 competitors to 1. This is probably exaggerated to some extent as a large number of service providers in the basin only do vertical work, so looking at the more service-intensive horizontal providers the ratio could be closer to 1.5 or 2 to 1. One barrier to entry that could keep many new companies from entering the Permian is the labor supply. We hear service providers have difficulties adding crews and even had to use commuter crews from other regions to be able to maintain their 24-hour pumping crews. Land Drillers As we look at our coverage universe and who has the largest exposure to the Permian, we find that HP and PTEN have the most rigs drilling horizontal wells in the play (Figures 37 &38). Figure 37: Horizontal/Vertical Split with Operator Market Share Source: Drilling Info Page 30 of 82

Figure 38: Rigs by Operator 60 50 40 30 20 10 0 HP PTEN NBR PDS PES UNT Source: Drilling Info We highlight the horizontal rig exposure because as this type of drilling continues to expand, the demand for AC rigs in the region is likely to continue to grow. Figure 37, on Page 30, shows what we believe is a highly fragmented market where ~46% of the horizontal rig market is held by smaller operators. This type of market along with the ease of moving rigs could cap regional dayrates for land drillers because of the amount of competition. As we have seen in other plays with similar maturity cycles, pad drilling is becoming more prevalent in the Permian, and the demand for rigs with specialized pad movement capabilities will likely continue to grow. The data points about rig movement capabilities are sparse, making it difficult to get a true sense of how many rigs are actually drilling on pads in the region. Many E&P companies are still in delineation mode in the basin, and we believe that we are still 1-2 years away from full manufacturing mode. After looking at initial high-level trends in the basin such as horizontal demand and the rise of pad drilling, the supply/demand model within the region becomes more complex. Operators are now able to drill more wells per rig as they move to pad drilling, yielding a more efficient capital spending profile. However, the basin is not likely approaching the inflection point yet when the horizontal rig demand stabilizes with growing efficiencies. Even with this as a future possibility, as we move through 2014, we would expect to see the horizontal rig adds keep up with the decline in vertical rig count. Looking at Figure 37, the horizontal rigs already outnumber vertical rigs and this is likely to persist through the year. In addition to rig activity, it is also important to examine dayrate trends. There has been very little change in rates between the different rig classes in the Permian over the past couple of years. The average dayrates for the smaller (less than 1,000 horsepower rigs) have declined about 1%, while the other two classes of rigs (1,000 hp / 1,500 hp) have seen dayrates move up slightly (Figure 39). Page 31 of 82

Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 January 27, 2014 Figure 39: Historical Dayrates $25,000 $20,000 $15,000 $10,000 $5,000 $0 500-999 HP 1,000 hp 1,500 hp Source: Rig Data Day Rate Report Dayrates should be relatively flat going forward, assuming the current environment persists for the two higher classes of rigs. This is despite our prediction for a slight increase in the rig count because rig operators have the ability to move rigs relatively easily into the basin, ultimately keeping pricing increases at bay. For the lower class rigs, a flattish dayrate environment is plausible, but as most of these rigs are drilling vertical wells, competition to maintain utilization may create some downward pressure on dayrates for this class. Utilization since early 2012 (Figure 40), has seen little change within the two larger classes of rigs, but a decent decline in the <1,000 HP class rigs. This trend is no surprise given the switching from vertical to horizontal drilling, but the utilization in the <1,000 HP class has held up slightly better than we would have initially thought with vertical rigs still useful for leasehold purposes. Figure 40: Utilization by Class 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% <1000 1000-1499 1500-1999 Source: Rig Data Biweekly Report As we dig a little deeper into the <1,000 HP class, the active rig count has declined ~40% while the utilization rate has only dropped ~20% since early 2012 (Figure 41). This tells us that as switching has taken place, rig operators have been removing these lower horsepower rigs from the play in an attempt to keep supply/demand in balance. While that appears to have helped maintain dayrates to some extent, the increased competition in these lower horsepower rigs as we enter 2014 will keep continued pressure on that class performance metrics. Page 32 of 82

Figure 41: <1,000 HP Active Rig Count and Utilization 300 250 200 150 100 50 0 80% 70% 60% 50% 40% 30% 20% 10% 0% Active Utilization Source: Rig Data Biweekly Report For the higher horsepower rigs, particularly the 1,500 to 2,000 HP classes, utilization has increased slightly while the active rig count has expanded over 140% since early 2012 (Figure 42). This signals that even though demand has been increasing in the basin, operators have ample amount of flexibility within their fleets to keep supply in line with demand. Again this is further support that the active rig count for the higher horsepower rigs should continue to improve, but that overall utilization for this class of rig should remain relatively stable in the mid to high 80% range. Figure 42: 1,500 1,999 HP Active Rig Count and Utilization 140 120 100 80 60 40 20 0 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Active Utilization Source: Rig Data Biweekly Report In summary, we would expect the horizontal rig count to exceed the vertical rig count at some point in 2014, and feel that there is still opportunity for companies like HP, PTEN, NBR, and PD to take market share with newer, higher horsepower AC rigs. We believe that the sub 1,000 HP rigs should continue to engage in a knife fight to maintain utilization and dayrates, while the higher horsepower rig count should increase with little inflection in dayrates due to the ease of moving rigs in and out of nearby basins. Page 33 of 82

Pressure Pumping and Completion Work Taking the next step down the service chain at least in terms of transparency, we examine the stimulation and completion services landscape. Here, the Company-specific data points are a little bit harder to come by, but by viewing the market in aggregate, we believe we have a fairly good idea of its composition. We first tried to estimate how much horsepower is currently available within the basin. After combing through data and talking with some of our companies, we come to the conclusion that there is roughly 3 million horsepower in the basin. One caveat is that with the Eagle Ford being so close in proximity and the ease of moving pumping crews between the two, the actual amount of horsepower in each basin at a given time could vary given the rig count and mix of work. From a Permian horsepower perspective, we estimate that HAL has the number one market share with about 400,000 hp, BHI has the number two market share with roughly 300,000 hp, and SLB would be number three in the basin. Even though the horsepower estimates are round numbers and are fluid estimates, these are the three market share leaders in the play, and should benefit the most given their presence and size. One interesting thing to consider when looking at the completion work being done in the Permian is whether lateral lengths become so long that a coiled tubing unit is no longer viable, requiring a well servicing truck instead. The cut off for a 2 3/8 coiled tubing unit is ~7,500 lateral feet. In our estimation, ~50% of Permian horizontal locations will be able to utilize coiled tubing units, while the remainder essentially needs a well service rig to do the completion work. Figure 43: Coiled Tubing Well Depth Capabilities Source: SPN Presentation While the basin is heading towards using longer lateral well designs, we get the sense though that the majority of wells drilled today are still able to be completed with a 2 3/8 coiled tubing unit and fall under that ~7,500 foot lateral cut off. The service providers in the basin have implied that the coiled tubing business does very well and that only 10-15% of the well service work done is completion work. Therefore, while part of the basin from a technical standpoint needs to be completed with something larger than a 2 3/8 coiled tubing unit, most the work that has been done thus far has not yet used lateral lengths that would require switching to well servicing rigs. Page 34 of 82

Midland vs. Delaware Similar to the migration of equipment and services between plays we see migration within the Permian. There are two major basins, Midland and Delaware, where we expect to see most of the migration. Consequently we compare the amount of horsepower, how many frac stages, and the amount of proppant necessary per well. The Midland has seen a significant increase in horizontal drilling over the past two years while the total rig count has remained essentially flat, as many operators have begun switching from vertical drilling. In contrast, the Delaware Basin has seen its horizontal rig count additions be incremental to the total rig count. Figure 44: Midland Rig Count 350 300 250 200 150 100 50 0 Total Midland Horizontal Midland Source: Baker Hughes Rig Count, Research Figure 45: Delaware Rig Count 200 180 160 140 120 100 80 60 40 20 0 Total Delaware Horizontal Delaware Source: Baker Hughes Rig Count, Research As we look at the Midland Basin, we would expect the horizontal rig count to continue to expand as more operators look to unlock the value from the prolific Wolfcamp shale. The Delaware Basin continues to see more horizontal adds and we would expect that to continue. The leading edge for the amount of horsepower required within the Midland Basin on a horizontal well is roughly 34,000-36,000 horsepower, with the Delaware Basin needing slightly less at 28,000-30,000 horsepower per well. These numbers are larger than previous levels and our expectations but are more likely leading-edge numbers. The average for the overall basin is probably closer to 20,000 horsepower today. The difference between leading edge and the average is largely due to the amount of vertical wells still Page 35 of 82

being drilled in the basin, and these wells require much less horsepower than the horizontal wells. In the Midland, the average stage count per well has increased nearly 50% over the past year from 20-21 stages per well to around 30 stages per well. The Delaware Basin does not require the intensity in stage count as most of these wells average 15 stages, but this is still up from 10-12 stages a year ago. While both of these numbers are more likely leading edge, the average stage count for the Permian Basin is likely around 20 per well. Given the well depths and number of stages per well, this leads to the thought of a large tonnage of proppant per well. For the Midland Basin, horizontal wells in the basin are averaging 8-9 million tons of proppant per well, and the Delaware Basin averages roughly 3-3.5 million pounds. Most of this proppant demand is comprised of white sand with some resin-coated sand usage as well. Some operators have discussed using brown sand in their Permian wells because it is so readily available, but results show that while well costs do come down, so do the long-term production levels. Looking at the possible demand opportunities for white sand in 2014 for the Midland and Delaware basins, we present both bullish and bearish cases below. The yellow in both boxes represents where we most likely are today and what we would expect the next year to look like. Figure 46: Midland Basin Proppant Demand Source: Baker Hughes Rig Count, HW Research Figure 47: Delaware Basin Proppant Demand Source: Baker Hughes Rig Count, HW Research While the supply of white sand in the Permian is very fluid, the increase in horizontal drilling along with the continued discussion around pumping more sand per stage with more stages per well should help create a tighter sand market come 2H14. Page 36 of 82

Crude Oil Infrastructure Takeaway capacity for growing liquids production is an issue for all onshore producing basins. Over the past few years, the balance between production and infrastructure capacity in the Permian Basin has been a delicate one, causing differentials between Midland WTI and Cushing WTI to widen considerably at times (Figure 48). As infrastructure constraints lessen with new pipeline capacity coming on line we expect to see differentials narrow and volatility to moderate. Ultimately, we believe the spot price in Midland will be set by transport differentials to Cushing of ~$1/Bbl, although producers with capacity on pipelines heading to the Gulf Coast will likely see higher realizations set by LLS. Figure 48: Midland Differentials to Cushing and LLS Midland - Cushing Differential ($/Bbl) $2 $0 Jan-11 ($2) Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 ($4) ($6) ($8) ($10) ($12) ($14) ($16) Midland - LLS Differential ($/Bbl) $0 Jan-11 ($5) Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 ($10) ($15) ($20) ($25) ($30) ($35) ($40) Source:, Bloomberg Total production out of the Permian Basin in 13 is estimated at ~1.36MMBbl/d, compared to takeaway capacity of just under 1.6MMBbl/d. Nearby refining capacity makes up ~25% of current takeaway capacity at ~400MBbl/d, with the remainder on pipelines heading to Cushing and the Gulf Coast (Figure 49) and a small amount of rail loading capacity. Over the next 12-18 months, an additional 760MBbl/d of pipeline capacity is expected to come on line, predominately heading to the Gulf Coast which should provide better netbacks to producers than heading up to Cushing. Figure 49: Pipeline & Refinery Locations Source: Concho Resources Company Presentation Page 37 of 82

Rail capacity to the West Coast is a common theme we hear in the market, however we get the sense producers are reluctant to commit volumes at this time given the outlook for adequate pipeline capacity over the next few years, which comes at a much lower cost than rail transport. Figure 50 below depicts expected production growth in the Permian in the next few years compared to takeaway capacity. Unless production grows at a much faster than anticipated rate, it appears pipeline capacity and nearby refiner demand will be more than adequate to handle expected volumes. In this scenario, we see rail as more swing capacity as needed, but not necessitating the build out of unit train facilities. Figure 50: Forecast Production vs. Takeaway Capacity Source: Laredo Petroleum Company Presentation Page 38 of 82

Permian Basin Company Updates Anadarko Petroleum Corporation... 40 Apache Corporation... 41 Approach Resources... 43 Athlon Energy... 45 Callon Petroleum Company... 47 Chesapeake Energy... 48 Chevron... 48 Cimarex Energy... 50 Concho Resources... 52 ConocoPhillips... 54 Devon Energy... 55 Diamondback Energy... 56 Energen Corporation... 58 EOG Resources, Inc.... 60 Forest Oil Corporation... 61 Laredo Petroleum... 62 LINN Energy / Linn Co... 64 Matador Resources... 65 Occidental Petroleum Corporation... 67 Pioneer Natural Resources... 69 QEP Resources... 71 Quicksilver Resources... 72 Range Resources... 73 Rosetta Resources... 74 Royal Dutch Shell... 76 SM Energy... 77 W&T Offshore... 79 Whiting Petroleum... 80

Anadarko Petroleum (APC - $81.09 - SO) Anadarko maintains a 330,000 net acre position in the Permian, concentrated in the Delaware Basin in Loving, Ward and Reeves counties. Activity levels have increased, with 3Q13 net sales volumes of 17,000 Boepd, with liquids accounting for ~60% of produced volumes. Figure 51 depicts Anadarko s Permian Basin Acreage. Figure 51: Anadarko s Permian Position Source: Anadarko Petroleum Anadarko exited 3Q13 with 10 operated rigs across the basin: 2 in the Bone Spring, 2 in the Avalon and 6 in the Wolfcamp. The Bone Spring/Avalon provide a strong base and the emerging Wolfcamp serving as an exciting new avenue for APC to pursue to grow liquids volumes in the basin. The Company currently estimates 1,000 Avalon locations and 200 Bone Spring drill sites, both of which have projected EURs of 400+ MBoe. Rates of return in the Avalon and Bone Spring are projected at 47% and 34%, respectively. In the emerging Wolfcamp play, as highlighted in Figure 52, Anadarko has completed six wells to date which have achieved gross IP rates of 1,000-1,600 Boepd and 30-day rates of greater than 500 Boepd. Given the current rig allocation, we anticipate additional Wolfcamp results will be provided in subsequent earnings releases and will become a larger focus for APC s Permian operations. Figure 52: Anadarko Wolfcamp Results Source: Anadarko Petroleum Page 40 of 82

Apache Corporation (APA - $82.42 - SP) In the third quarter, Apache achieved a corporate milestone in the Permian, as over half of the Company s operated rigs are now drilling horizontal wells as opposed to the traditional vertical program that defined APA for so many years. Furthermore, given the recent divestiture of the GOM shelf assets, the sale of certain Canadian assets and the sell down of interest in Egypt, Apache s onshore U.S. programs in the Permian (along with the Mid- Con) look to take on a more central role in growing oil and liquids volumes. With 1.6 million net acres and an estimated inventory of over 34,500 locations, Apache has significant exposure to various regions within the prolific and reinvigorated Permian Basin. Figure 53: Apache s Permian Acreage Source: Apache Corporation Over the past few years, Apache has accelerated the exploration and development of horizontal pay horizons in the Permian Basin, proving the concept in over 11 plays to date. In 2013, the Company has targeted nine additional plays for horizontal potential. In the Delaware, Apache will target the Avalon, 1 st Bone Spring and Wolfcamp intervals while in the Midland, the Company is pursuing the Lower Spraberry and Mississippian Lime. Apache is also incorporating horizontal drilling in the Central Basin Platform. In 3Q13, Apache s Permian division drilled 155 net wells with a 45-rig program that produced quarterly volumes of 131,665 Boepd (76% liquids). We expect Apache to have maintained its 44-rig count in 4Q13, 23 of which will drill horizontal wells. Cost control has served as a focal point for APA and the Company has diligently worked to reduce well costs in the basin by decreasing drilling days and reducing frac costs. Midland Basin Activity: In the Midland, 3Q13 activity highlights centered on the horizontal Wolfcamp in the Barnhart area of Irion County, Reagan and Upton counties and on the Cline Shale. In the Barnhart area, Apache is currently running a 6-rig program and has drilled 56 net wells year-to-date. In Reagan and Upton, Apache has one rig operating in each area targeting the Upper and Middle Wolfcamp. In the Cline, where APA maintains a 520,000 net acre position, the Company is operating three rigs to evaluate the pay horizon potential across its acreage. Activity to date has been focused in the Deadwood area in Glasscock County. In addition the its horizontal program, Apache controls ~625,000 net acres in the Midland with vertical drilling potential an estimated 17,800 locations with 1.7 BBoe of resource potential. The Company continues to focus on building inventory in the Fusselman play and on high grading its Wolfwood locations. Page 41 of 82

Delaware Basin Activity: The Delaware serves as an emerging area for Apache. The Company currently maintains a 287,000 net acres position with exposure to multiple pay zones. Figure 54 overlays Apache s Delaware acreage with peer activity. Apache is currently operating two rigs in the Pecos Bend area of Loving and Reeves counties. Drilling is targeting the third Bone Spring interval and the Upper Wolfcamp. Figure 54: Delaware Basin Profile Source: Apache Corporation Other Activity: Aside from its holdings in the Delaware and Midland, Apache controls meaningful acreage positions and strong production in both the Central Basin Platform and the Northwest Shelf. While the CBP is often synonymous with repeatable vertical drilling and enhanced oil recovery programs (i.e. waterflood and CO2) Apache is applying horizontal technology to the CBP to further enhance its Permian program. Apache estimates that it has 780,000 net acres with estimated 690 MMBoe of resource potential from 9,800 locations. During 3Q13, three rigs spud a total of six horizontal wells in the Three Bar Shallow Unit focused on the lower Wichita Albany landing zone. Results are encouraging with 30-day IP rates of approximately 1,000 Boepd. Northwest Shelf Activity: 70,000 acres in the Yeso with 1,800 locations. Continue to drill with two vertical rigs and one hz rig. Page 42 of 82

Approach Resources (AREX - $20.32 - SO) AREX is a pure play Permian operator with 95.5MMBoe YE12 proved reserves and more than 149,000 largely contiguous net acres in the Southern Midland Basin in Crockett and Schleicher counties and over 2,000 horizontal Wolfcamp drilling locations. Figure 55: AREX Offset Operators Source: Approach Resources Company Presentation A Permian player dating back to 2004, AREX has drilled more than 600 Permian wells to date, historically targeting deeper objectives such as the Canyon, Strawn and Ellenburger zones via vertical developments. In recent years, the Company has moved uphole to target the Wolfcamp and Clear Fork formations in its vertical wells, in addition to testing horizontal zones in the Wolfcamp. Beginning in 2013 the Company began primarily drilling horizontal wells and is currently running 3 HZ rigs targeting the Wolfcamp formations with plans to complete ~40 HZ wells in its $300MM, 2013 capital program AREX s acreage is split into two named areas: Pangea (~147,000 gross acres), where the majority of the Company s activity to date resides, and Pangea West (~19,000 gross acres). Since going public in 2007, the vast majority of the Company s drilling has been in the North Pangea area of its Southern Midland Basin acreage. The Company primarily drilled vertical wells targeting the Wolfork formation up until 2011 and has since transitioned to a horizontal developmental drilling program targeting the Wolfcamp formation. AREX is one of first Company s in Midland Basin to be in full HZ development mode and is benefiting greatly on the cost side, as the Company s average D&C cost per well during 3Q13 was only $5.4 MM, which is possibly the lowest in all the Permian moving towards $5.1MM. A partial reason for the lower well costs however is that the Company is in the more southern portion of the basin, where the target formations are shallower than in counties like Midland and Glasscock. In addition, AREX s acreage position yields a gassier production mix than the more northern counties and in 3Q13 the Company realized an oil cut of ~39%, which is much lower than other peer Midland Basin operators such as FANG (75%) and LPI (49%) who operate primarily in the counties north of AREX s core acreage position. Despite the gassier production, the Company has still done an impressive job of investing in infrastructure such as salt-water disposal systems and pipelines that have aided the Company s well cost reductions and reduced drilling days down to 12 days in 3Q13. Additionally we expect oil volumes to move towards 50% of total production as development mode builds a stable base. Page 43 of 82

AREX s is currently planning to continue running three horizontal rigs throughout 2014 and plans to drill ~75% more wells than during 2013 as a result of developmental drilling and faster completion times. The Company recently completed its best HZ well to date in central Pangea with an IP of 1,334 Boepd (76% oil) targeting the Wolfcamp B. The Company has also recently seen an increasing number of its wells outperforming its 450 MBoe EUR type curve because of higher IP rates and shallower decline curves compared with the Company s base case models. Figure 56: AREX s Permian Position Source: Approach Resources Company Presentation AREX s 2014 plan will continue to focus on development-drilling in its core northern Pangea acreage in order to most effectively take advantage of its infrastructure investments and keep costs trending lower while focusing on stacked horizontal targets with ~7,000 + laterals. Page 44 of 82

Athlon Energy (ATHL- $28.83 - SO) Athlon is a pure play Permian player that recently went public in August of 2013. The Company has ~109,000 net acres in the fairway of the Midland Basin located primarily in Howard, Midland, and Glasscock counties. At YE12, the Company had ~86.6 MMBoe of proved reserves and 3Q13 production of ~13 MBoepd. Athlon s acreage is split across several counties throughout the Midland Basin including: Howard (52%), Midland & Upton (~18%), Glasscock (~13%), Iron & Reagan (~8%), and Andrews & Martin (~8%). As depicted in the map below, the majority of the drilling to date has focused on Howard, Midland, and Glasscock and the Company plans to continue drilling heavily in these areas in its newly initiated horizontal drilling program. Figure 57: ATHL Acreage & Wells Drilled Source: Athlon Energy Company Presentation Athlon was formed in 2010 and up until its recent IPO had been an exclusively vertical operator in the Permian having drilled >300 vertical wells to date with some of the best vertical IP rates and EUR s (~149 MBoe) in the basin. To date the Company has ~3,900 vertical drilling locations remaining, which are prospective for multi-formation completions. The vertical program represents the core value of the Company as ATHL is currently running 7 vertical rigs with plans to add an 8 th rig in 2014. The Company has been steadily improving operational results in vertical program since its inception and currently has an average well cost of ~$2MM and a direct LOE/BOE cost of ~$7.19 in 3Q13. The Company recently raised ~$296MM in its August 2013 IPO using a portion of those proceeds to initiate a complimentary horizontal drilling program primarily targeting the Wolfcamp formation. ATHL recently announced the first 2 Wolfcamp B well results in Midland County from the Company s recently initiated horizontal drilling program, which produced very impressive IP rates. The first Wolfcamp B test achieved a 30-day IP rate of ~1,200 Boepd (77% oil) while the second test achieved a 20-day IP rate of 1,759 Boepd (71% oil). In addition, ATHL has already drilled 2 Wolfcamp A wells in Glasscock County and is beginning to drill the first of its 3 Wolfcamp A wells in Howard County. Page 45 of 82

ATHL plans to continue running their current HZ rig throughout 2014 while adding another HZ rig in 2Q14 to accelerate drilling in the Wolfcamp in Midland County. With the success of offset operators and the Company s first 2 successful tests in the area, it is no surprise that Midland County will be the initial focus area for Athlon s horizontal program. However, the biggest long-term growth driver for the Company will be the successfulness of HZ drilling in Howard County by both Athlon and the industry where activity is picking up in both the Wolfcamp A and Cline formations. The only 30-day well today is the Element Petroleum SFH Unit 23 #1H that achieved a 30-day IP rate of ~649 Boepd targeting the Wolfcamp A. We could receive results from several of the wells below in the next couple of months in addition to Athlon s first HZ wells sometime in late 2Q14 or 3Q14. Figure 58: Howard County Offset operator Wells Source: Athlon energy Company Presentation Athlon s 2014 drilling program has not yet been released; however, we predict it will be in the range of $525 600MM, which the Company is more than capable of funding. ATHL has ample liquidity with a newly increased borrowing base of $525MM and a debt to book cap of only 45% and debt to market cap of ~15%. Page 46 of 82

Callon Petroleum (CPE- $6.66 - SP) Callon Petroleum recently finalized the sale of its final offshore GOM & Haynesville assets completing the Company s transformation into a pure play Permian name. Callon now holds ~35,000 net acres in the Midland Basin with ~13,300 net acres in the heart of the Midland Basin fairway prospective for HZ drilling in the Wolfcamp and vertical drilling in the Wolfberry. The transformation into a Permian player has greatly benefited Callon shareholders by simplifying the story and improving execution in the Company s horizontal drilling program. The recent transaction along with the redemption of half of the Company s 13% senior notes has also greatly improved the Company s balance sheet and reduced its current debt to book cap to 22%. CPE divides its Wolfberry/Wolfcamp plays amongst 7 fields in three different areas: the southern, central, and northern Midland. The core proved value of the Company is its vertical Wolfberry play in its southern and central Midland fields however, the majority of the upside remains in the ongoing development of the horizontal Wolfcamp in this same area in addition to some other zones (Spraberry, Cline, etc.) that the Company has yet to test. Figure 59: CPE Permian Field Locations Source: Callon Petroleum Company Presentation Page 47 of 82

CPE has made a strategical decision similar to that of many operators in the basin who are choosing to focus primarily on horizontal drilling and development moving forward. The Company plans to drill ~22 HZ wells and only 9 vertical wells in its $170MM revised 2013 CAPEX budget. The primary area of focus for Callon has been in its Southern Midland Basin acreage where the Company currently has 11 HZ wells producing 3 flowing back and 3 completing primarily targeting the Upper and Lower Wolfcamp B. The ~10,000 net acres in the area are the most valuable for the Company as it has been largely de-risking by both industry and Callon and represents ~311 of its remaining HZ drilling locations. We are currently modeling a ~530 MBoe EUR type curve for the Upper Wolfcamp B in this area with a ~$6.5MM well cost which generate IRR s in the range of 35-50% in the current commodity pricing environment. Callon is also becoming more active in the Wolfcamp formation of its central Midland Basin position in Midland County where it is currently drilling 2 Wolfcamp wells. The Company is taking a more passive role in its northern Midland acreage, which is prospective for two horizontal Mississippian formations. There has been limited industry activity in Borden and Terry counties but current results will not influence the Company to redirect a substantial amount of capital from its southern and central acreage. Figure 60: CPE HZ Permian Inventory Breakdown Source: Callon Petroleum Company Presentation Callon plans to continue to focus on drilling and developing its southern acreage into 2014 probably running 3 HZ rigs however, the Company has not released its 2014 drilling program. Investors are anticipating some type of acquisition from Callon during 2014 due to management s recent comments before and after the sale of its GOM Medusa asset. The Company still has ~$42MM in net proceeds remaining from its asset sale and we could see the Company being active in adding bolt on acreage or acreage in another area in the Permian with a transaction likely not exceeding $200MM. Page 48 of 82

Chesapeake Energy (CHK- $26.88 - SO) Seeking to reduce leverage, fund its capital program and reorganize the asset portfolio, CHK has sold the majority of its assets in the Permian Basin. During the 2Q12 earnings call the Company announced a transaction to sell producing assets in the Midland Basin to EnerVest and in September of 2012, Chesapeake announced that it had entered into an agreement to sell the majority of its remaining Permian assets to Shell and Chevron. In total, the gross proceeds were $3.3 billion. The Company s Southern Delaware Basin acreage was sold to Shell while the northern Delaware acreage was sold to Chevron. Following the completion of the transactions, which occurred in late October 2012, CHK maintains ~470,000 net acres of undeveloped leasehold in the Midland Basin. We do not anticipate that these assets will serve as a primary focal point for the Company and could ultimately be sold to help the Company further reduce debt or provide additional cash to fund ongoing operations in the core areas of the portfolio. Chevron (CVX- $116.29 - SP) Chevron is currently the second largest producer in the Permian Basin, with 119MBoepd of production in 12 and nearly 2MM acres under lease, including ~1MM acres in the Delaware Basin. By 17 the Company sees its net production in the Permian reaching ~175MBoepd, a CAGR of ~8%. For 13 CVX planned to drill 340 gross wells in the Midland Basin and 100 gross wells in the Delaware Basin, with 23 rigs running by YE. Page 49 of 82

Cimarex Energy (XEC- $98.52 - SP) Cimarex has built a substantial position in the Permian Basin, having accumulated ~438,000 net acres to date. The majority of the Company s position falls in the Delaware Basin, though it also has a leasehold position in the Abo play in the Northwest Shelf. Aside from the vertical Abo play, XEC s most active plays in the Delaware Basin include a 2 nd & 3 rd Bone Spring play in central Eddy and Lea counties, a 3 rd Bone Spring play in Ward County, a 2 nd Bone Spring in Culberson County, and Wolfcamp A,C, & D plays in Culberson, Reeves, and Ward counties. Figure 61: XEC Delaware Basin Acreage Source: Cimarex Energy Company presentation As the Company s more mature Mid-Con. assets have entered into full development mode, XEC s Permian plays have shot to the forefront of the Company s operational focus and CAPEX spending. At 696.8 Bcfe, the Permian comprises 31% of XEC s YE12 reserves and at 352 MMcfe/d, it constituted 49% of the Company s 3Q13 average daily production. We are currently projecting a ~19% increase in Y/Y production from the Permian during 2014. Additionally, XEC currently plans to spend ~65% of its ~$1.6B CAPEX budget for 2013 in the Permian and $1.4B in total CAPEX in 2014. XEC exited 3Q13 operating 12 rigs in the Delaware with 8 drilling the Bone Spring zones and 4 drilling in the Wolfcamp. The Company also plans to bring 2 additional rigs down from its Mid-Con operations sometime around YE13 to drill the Wolfcamp. The Company is currently planning to drill ~140 gross Bone Spring wells in 2013 targeting the 2 nd & 3 rd Bone Spring in Eddy and Lea counties, the 3 rd Bone Spring in Ward County, and 2 nd Bone Spring in Culberson County. Additionally XEC has ~180,000 net acres prospective for multiple Wolfcamp horizons including the A, C, & D benches of the play. The Company has ~100,000 net acres in Culberson County and recently announced a JV with Chevron to develop the area. XEC/CVX is already producing from the D & C benches of the Wolfcamp and has begun testing the A Bench in Culberson. In Reeves County, the Company has ~40,000 net acres and is primarily focusing on the Wolfcamp A where it has two wells producing at an avg. 30-day rate of 925 Boepd (63% oil) in addition to a 10,000 lateral well that produced a 30-day rate of ~1,816 Boepd. Finally, XEC continues to run 1 rig targeting the Wolfcamp A in the Company s 32,000 net acres in Ward County. Page 50 of 82

Figure 62: XEC s Delaware Wolfcamp Acreage Source: Cimarex Energy Company Presentation Cimarex recently announced that its $1.4B Permian Basin budget for 2014 will focus ~$1.2B on drilling and completion activities allocated towards the Wolfcamp ($600MM), the Bone Spring ($375MM), and the Avalon Shale ($175MM). We believe the 2014 drilling program will provide XEC with several operational catalysts including: testing its new frac stimulation across all of its acreage, testing several stacked laterals, drilling more long lateral wells in Reeves County, and testing a new completion design in the Company s 80,000 net acres in the Avalon. Page 51 of 82

Concho Resources (CXO- $96.89 - FS) Concho is one of the premier Permian operators with positions in the Northwest Shelf, Midland and Delaware Basins that offer a combination of conventional oil plays and unconventional liquids-rich shale plays. CXO offers investors unique leverage as a pure Permian play with the basin representing 100% of CXO s 447 MMBoe (61% Oil) year end 2012 proved reserves and 100% of the Company s 9.4 MMBoe 3Q13 production. However, the Company does offer investors a diversified asset portfolio by having exposure to multiple high-return plays within the greater Permian. CXO built its ~630,000 net acre Permian position through an aggressive acquisition strategy, which includes the Company-transforming Marbob acquisition in 2010 and the acquisition of Three Rivers Permian assets that added significant inventory and drilling locations to Concho s Delaware and Midland Basin assets in 2012. These acquisitions provided the Company the necessary acreage to develop one of the premier drilling programs in the Permian and have enabled Concho to be on the forefront of current horizontal drilling activity. Figure 63: CXO Delaware Basin HZ Wells Source: Concho Resources Company Presentation The core value of the Company is its Vertical Yeso and Wolfberry acreage; however, CXO has been increasing its focus on horizontal activity because of the recent success of the 2 nd and 3 rd Bone Spring in the northern & southern Delaware Basin, and the HZ Wolfcamp in the southern Delaware and Midland Basins. The Company also has HZ prospects in the Cline in Midland Basin and the Abo & Yeso in the NW New Mexico shelf. Concho has capitalized on its quality acreage positions and efficient drilling programs to develop one of the best cash margins in the Permian averaging ~$58/Bbl in 3Q13. The Company plans to continue to focus on high return projects in the future as evidenced by its significant commitment to horizontal drilling in its future CAPEX plans. Concho s transition to primarily horizontal drilling signifies a change in the Permian that we expect many operators to follow in the near future. We are already seeing plenty of evidence of this transformation in the Permian and we expect that trend to increase rapidly in the next couple of years. Page 52 of 82

Concho s horizontal activity has been predominately in the northern Delaware to date targeting the 2 nd and 3 rd Bone Spring. Concho is the most active operator in the area and has made it clear that the Delaware will continue to be the focus for the Company moving forward. Concho recently drilled one of if not the best HZ wells to date in the Permian near the Texas/New Mexico which achieved an IP rate of 4,600 Boepd targeting the 2 nd Bone Spring with only a 4,600 lateral. This new well was certainly an extraordinary result for CXO; however, the Company has been extremely successful with majority of its 2 nd Bone Spring wells in the northern Delaware having drilled ~108 HZ 2 nd Bone Spring wells as of 3Q13 with an avg. 30-day IP rate of 812 Boepd (78% oil). While the northern Delaware will remain the Company s primary operating area moving forward the southern Delaware and Midland Basin are going to see a significant ramp in activity in 2014 and beyond. The southern Delaware acreage is located mostly in Reeves and Pecos County and is prospective for the Upper Wolfcamp with additional upside in the Delaware Sands, Avalon, Bone Spring, and Middle Wolfcamp. CXO has identified 200 Upper Wolfcamp drilling locations and has drilled 15 wells to date in the area with a projected EUR type curve of 500-750MMBoe. The Company plans to exit 2013 running 6 rigs in the area and will continue the 6 rig program throughout 2014. In the Midland Basin CXO has not been as active as many other Permian peers but the Company is expecting a significant ramp in activity in 2014. To date CXO has drilled 7 HZ Wolfcamp wells mainly in Upton County with an average 30-day IP rate of 695 Boepd (75% oil). The Company currently plans to exit 2013 with 3 rigs and increase to 7 rigs in 2014. Figure 64: CXO s Successful HZ Wells Source: Concho Resources Company Presentation CXO recently announced a 2014 CAPEX budget of $2.3 billion, ~90% of which will focus on developing the Company s acreage in the northern Delaware and delineating its acreage in the southern Delaware and Midland Basins with a 37 (32 HZ) rig drilling program up from ~18 HZ rigs as of the Company s 3Q13 earnings call. The 2014 program is the beginning of a newly implemented 3-year program for Concho to double current production by YE16 with an annualized average growth rate of ~25%. The Company plans to accelerate HZ activity in 2015 and 2016 by running in the range of ~40 to ~50 HZ rigs respectively in the Permian. Page 53 of 82

ConocoPhillips (COP- $66.57 - SP) COP holds approximately 1.1MM net acres in the Permian Basin, which is all currently held by production. The Company is active in both conventional and unconventional plays and sees >1BBoe of resource across its acreage. In its Permian conventional program, COP aims to invest ~$3B over the next 5 years with plans to add ~40MBoepd by 17, a CAGR of ~7%. In the unconventional program, COP is testing several plays in both the Delaware (COP 150k acres) and Midland Basin (COP 90k acres). Early tests of Avalon wells in the Delaware Basin have shown ~60% liquids production and the Company sees at least two producing intervals, with two to three potentially in the Wolfcamp. Figure 65: COP s Permian Basin Acreage Position Source: Company Reports Page 54 of 82

Devon Energy (DVN - $59.52 - SO) Boasting a robust 1.3 million net acre position, DVN ranks as a leading operator in the Permian Basin with exposure to a variety of emerging and established plays within the region. The Company currently operates 23 rigs and achieved 3Q13 production of 82,000 Boepd, of which 60% was oil. We expect DVN s activity levels to remain elevated for the remainder of the year and into 2014. In 2013, DVN anticipates total capital expenditures of $1.6 billion and to drill over 350 wells. Figure 66 depicts DVN s Permian Basin oillevered opportunities. DVN maintains 320,000 net acres in the Bone Spring, 150,000 net acres in the Wolfberry, 117,000 net acres in the Wolfcamp in the southern Midland Basin and 377,000 net acres that are prospective for Cline development in the eastern shelf of the Midland. Figure 66: DVN Permian Exposure Source: Devon Energy In the Delaware, DVN is currently focused on developing low-risk, high-impact wells in the Bone Spring with 12-13 operated rigs. The Company estimates an inventory of ~1,400 locations in the Bone Spring which should act as a meaningful driver of future oil production growth. In 3Q13, DVN added 24 Bone Spring wells to production with 30-day IP rates of 690 Boepd, 72% oil. Also in the Delaware, DVN is testing its Wolfcamp potential in Reeves and Ward counties. The Company has drilled its initial Wolfcamp test in Ward County and we hope that DVN will disclose initial results when the Company reports 4Q13 results. DVN estimates ~140,000 net acres in the Delaware are prospective for Wolfcamp Development. In the Midland, DVN is currently developing the Wolfcamp with five operated rigs. The incorporation of pad drilling has helped in reducing drill times to under 15 days and increases efficiencies that result in lower operating and well costs and in turn boost returns. DVN currently maintains ~117,000 net acres that are prospective for the Wolfcamp and estimates an inventory of over 800 locations. Current well costs are approximately $5.5 million. In 3Q13, DVN added 26 Wolfcamp wells to production with 30-day rates of ~400 Boepd, consisting of 73% oil. DVN s southern Midland Wolfcamp acreage is concentrated in Reagan, Irion and Crockett counties. Page 55 of 82

Diamondback Energy (FANG - $48.87 - SO) Diamondback Energy launched its IPO in November of 2012 and raced onto the scene as one of the best performing E&P names in 2013 up ~175%. Shortly following its IPO FANG quickly began expanding its HZ drilling program and has now become one of the premier HZ operators in the Permian. The Company holds ~65,000 net acres primarily in Midland, Ector, Martin, and Andrews counties with some additional non-contiguous acreage in Upton, Crockett, and Dawson counties. FANG s initial strategy into horizontal drilling was to be a fast follower, allowing other operators to do some of the initial testing and then move into to the most prospective areas. After watching other operators drill horizontals for some time, FANG identified Midland County as its first and primary drilling location focusing on 5,000 and 7,500 lateral wells targeting the Wolfcamp B. The Company is now actively delineating and developing its acreage positions across the Midland running 4 HZ rigs and 1 vertical rig primarily targeting the Wolfcamp B; however, the Company recently completed a successful Clearfork test in Andrews County and a Middle Spraberry test in Midland County. The Company is currently using a 600MBoe EUR type curve on its 7,500 Wolfcamp laterals and is seeing evidence from the recent Spraberry test that this zone could outperform that curve making it a great potential candidate for future stacked laterals with the Wolfcamp. Figure 67: FANG Acreage Position Source: Diamondback Energy Company Presentation One of the most impressive aspects of the Company s operations is its ability to analyze and process drilling data, which allows the Company to improve production rates, frac designs, and well costs. As of October 2013, FANG had total production of 10,500 Boepd including 24 wells on production in the Wolfcamp B with another 7 wells in development. In addition, during 3Q13 the Company announced that for the third consecutive quarter it had achieved a >20% reduction in LOE/BOE costs bringing the number down to $7.27 for 3Q13. The cost reductions and improved production rates have led to some of the best operating efficiencies in the Permian and in 3Q13 the Company realized a cash margin/boe of $69.82. Page 56 of 82

Figure 68: FANG HZ Drilling Locations & EUR s Source: Diamondback Energy Company Presentation Diamondback was one of the first companies to come out with its preliminary 2014 drilling in November of 2013. The Company said that it expects to spend ~ $425 - $475MM on its 2014 drilling program and plans to add a 5 th horizontal drilling rig. We expect FANG to continue to drill 7,500 laterals as they have been and 5,000 laterals where there are acreage constraints. However, management has also stated that they are very interested in testing some 10,000 laterals in the Wolfcamp and possibly the Spraberry. We also expect to see the Company experiment with stacked laterals. FANG recently participated in a stacked lateral targeting the Lower Spraberry and the Wolfcamp B and results should be released sometime in 1Q14. Following the results of that stacked lateral, the Company will assess their current inventory and determine the best intervals to target in its operated stacked laterals. FANG has an excellent balance sheet in order to fund the additional planned growth initiatives it has set forth for 2014 with a current debt to book cap of only 35% after issuing its first major debt deal in September of $450MM in notes to finance its recent mineral rights acquisition in the Midland. Page 57 of 82

Energen Corporation (EGN - $69.38 - SO) The growth story continues for this emerging E&P Company that has amassed ~300k net acres in the Permian between the Midland (Wolfberry, Wolfcamp), Delaware (3rd Bone Spring, Wolfcamp) and Central Basin Platform through ~$1B of acquisitions since 2009. More recently, the Wolfcamp s potential has shown itself to be the growth driver for Energen, leading the Company to turn its sights on growing its oil and NGL production by +20% this year and 14% in 2014, while its attention on natural gas declines. What has been the most active drilling program in the past for Energen, the vertical Wolfberry program in the Midland Basin will be scaled back in 2014 to make way for the horizontal Wolfcamp. The Company holds ~63k acres and is currently finishing a 126 well vertical program for 2013, but has plans to run just 2 rigs in 2014 when this time nearly two years ago a 7-8 rig program was the long-term plan. Figure 69: EGN s Midland Basin Position Source: Energen Company Presentation Staying in the Midland Basin, EGN holds 70k net acres with ~2,000 potential Wolfcamp locations. The 7-well program in 2013 has been focused mainly on the Wolfcamp A bench in Glasscock County. The Company has achieved consistent results thus far with peak 20 and 30-day averages of ~700 Boepd (~65% oil). EGN will accelerate drilling in Glasscock County during 2014, running between 4-6 rigs in the play. We also expect the Company to continue to delineate the other Wolfcamp benches and the Cline in 2014. The 3rd Bone Spring in the Delaware Basin is approaching peak production for EGN as it now has just ~36 remaining locations across 30k net acres. A 3-rig horizontal program is anticipated for 2014 while the Company looks to finish drilling its current Bone Spring inventory. Page 58 of 82

Figure 70: EGN s Delaware Basin Position Source: Energen Company Presentation Energen has 114k net acres in the Delaware Basin Wolfcamp with 5 wells producing (9- well program in 2013) across Reeves, Winkler, and Ward counties. The promising Bodacious C7-19 #1H well in Reeves Co. has the Company s focus there after achieving peak 30-day average production of 1,671 Boepd (61% oil). The Wolfcamp remains the main growth driver for the Company s Delaware acreage moving forward and we expect Wolfcamp delineation to continue with +3,000 potential locations and a 2 rig program. Page 59 of 82

EOG Resources (EOG - $165.53 - SO) Since our initial report publication, the Permian Basin has come more into focus for EOG, but still ranks behind the Eagle Ford and Bakken in terms of core development activities. While EOG has exposure to both the Midland and Delaware areas of the Permian, the Company has favored activity in the Delaware as it is exhibits less geological complexity and greater consistency in results. Figure 71 summarizes EOG s acreage position and targeted plays in both the Midland and Delaware. Figure 71: EOG Permian Exposure EOG - Permian Basin Exposure Play Area Net Acres Potl. Locations EUR/Well Leonard Delaware Basin 73,000 1,600 500 MMBoe Wolfcamp Delaware Basin 134,000 1,100 800 MMBoe Wolfcamp Midland Basin 113,000 ND 430 MMBoe Source: EOG Resources & The Leonard shale generates the highest rates of return in EOG s Permian portfolio (stated to be 100% ATAX) and the Company expects to accelerate development in 2014. EOG has drilled a total of 54 wells to date in the Leonard. Similar to the Leonard, the Wolfcamp in the Delaware offers three distinct pay zones for horizontal development and represents EOG s second highest rate of return project (60% ATAX). The Company is early in the play s life cycle, but results are promising and midstream constraints have been eliminated, due in part to a high-pressure gathering system coming on line in October 2013. In the Midland, the Wolfcamp remains EOG s primary target, but development has lagged versus the Delaware plays. EOG is currently evaluating its acreage, but results in Irion and Crockett counties are encouraging. EOG is currently incorporating micro seismic and 3D imaging to improve completion effectiveness and recovery factors. Figure 72 provides a snapshot of EOG s typical well profile and well cost by play. Figure 72: Permian Well Profiles EOG - Permian Well Profile Play Area % Oil % NGL % Gas Well Cost ($mm) Leonard Delaware Basin 50% 26% 24% $5.5 Wolfcamp Delaware Basin 34% 32% 34% $6.5 Wolfcamp Midland Basin 42% 30% 28% $5.0 Source: EOG Resources & Page 60 of 82

Forest Oil (FST- $3.46 - SP) When we first published our initial report, FST had recently reported that the Company had amassed a 51,000 net acre position in the Midland basin prospective for the Wolfcamp Shale that would further bolster the Company s footprint in the basin. Since that time, the Company has undergone managerial changes, operational challenges and financial difficulty, which has resulted in the Company looking to divest non-core assets. In September of 2013, FST executed one level of this strategy, announcing the sale of a portion of its Midland Basin assets for $35 million. The transaction included 52,350 net acres located in the western portion of Crockett County, Texas, which equates to a sale price of ~$670/acre. Following the closing of the transaction in mid-september, FST now maintains a 60,250 net acre position in the Permian Basin, concentrated in Pecos, and Reeves counties. FST currently has 2 active wells (identified by green stars in Figure 73) that achieved first production in September 2012. FST currently does not have any additional permits for wells. Ultimately, we view this asset as a non-core divestiture candidate. Figure 73 highlights FST s acreage position relative to other operators in the area. Figure 73: FST Permian Acreage Position Source: Forest Oil Page 61 of 82

Laredo Petroleum (LPI - $25.31 - SO) Laredo Petroleum is one of the premier pure play Permian operators focusing the majority of its drilling horizontally in the Cline and Upper, Middle, & Lower Wolfcamp formations in addition to its complimentary vertical Wolfberry program. Laredo shed the bulk of its non-permian assets in May of 2013 when it sold its producing Anadarko Basin Assets for ~$438MM to ramp drilling in the Permian. Laredo currently holds ~141,230 net acres in the heart of the Midland Basin in its Garden City acreage based predominantly Reagan and Glasscock counties. Figure 74: LPI Acreage & HZ Completions Source: Laredo Petroleum Company Presentation Laredo is one of the most active horizontal operators in the basin having drilled ~79 horizontals targeting the Cline and the Wolfcamp zones as of 3Q13. The Company produces some of the best IP rates in the basin and has been most active in two areas: the Cline where it has drilled 37 wells with an average 30-day IP rate of 594 Boepd and the Upper Wolfcamp where it has drilled 32 wells with an average 30-day IP rate of 717 Boepd. To date, the Company has focused its Cline drilling in the Glasscock County acreage and its Wolfcamp drilling in the northern Reagan County acreage; however, LPI is in the early stages of drilling stacked laterals across its entire acreage position. Laredo recently completed its first 3 well stacked lateral pad targeting the Upper, Middle, & Lower Wolfcamp which came on with a 3-stream 24-hr rate of 3,778 Boepd. Laredo is planning to spend ~42% of its ~$950MM 2014 capital program on HZ development running 6 HZ rigs and drilling ~ 50-60 development wells. In addition, the Company is planning to drill 12-14 HZ delineation wells and continue its vertical development program drilling 110 120 wells while running 5 rigs. The HZ development program will continue to test 2, 3, & 4 well stacked laterals targeting the different Page 62 of 82

Wolfcamp Zones and the Cline. In addition to testing different zones, Laredo will also focus on finding the optimal spacing for the pads. The Company currently estimates that 660-acre initial spacing using offset pads will create the best opportunity for maximum reservoir drainage under the development program. While Laredo s stacked lateral paddrilling program is still in its infancy, the first result was encouraging and we believe once the Company has the opportunity to test different intervals and spacing it will be able to shift the program into full development mode sometime in 2015 or 2016. Figure 75: LPI Stacked Lateral Development Source: Laredo Petroleum Company Presentation Over the past year, Laredo has successfully transformed not only the operational strategy and focus of the Company but also its financial flexibility. LPI has reduced its debt significantly through its divestiture of its Anadarko Basin Assets in May of 2013 and its August 2013 follow-on equity offering. Because of these two actions, the Company has lowered its debt to book cap to ~47% and its debt/nev down to 21% essentially in line with its peer group as of 3Q13. Furthermore, the Company currently has ~$825MM available under its credit facility and ~$265MM in cash. Page 63 of 82

LINN Energy/Linn Co (LINE - $33.04 - FS / LNCO - $32.46 - FS) After LINN s recent purchase of BRY, the Company now has ~164,000 net acres in the Permian, which includes acreage on both the Delaware and Midland basin sides. The Company has total production of 26,155 Boepd and proved reserves of 160 MMBoe. The most valuable acreage is ~60,000 net acres in the heart of the Midland Basin, shown in the following chart and prospective for horizontal Wolfcamp drilling. Because of LINN s status as an MLP, an asset swap netting cash flow for the non-producing horizontal potential could be a very good deal, and we would not be surprised to see such a transaction in 2014. We estimate the core Midland Basin acreage could be worth $15,000/acre to $25,000/acre. LINN purchased ~4,800 Boepd of Clearfork production in September 2013 for $525MM. Figure 76: LINN Energy Midland Basin Acreage Source: LINN Energy Company Presentation Page 64 of 82

Matador Resources (MTDR- $19.48 - SO) Matador has built a 44,835 net acres position in the Delaware Basin, which we subdivide into 4 regions. The first region is called Ranger-Querecho and is located in central Lea County, NM. The second is the Wolf prospect located in Loving County, TX. The third, and most recent addition is Twin Lakes, north of Ranger-Querecho in Lea County, NM. Finally, the fourth prospect is called Indian Draw and is located in Eddy County, NM. MTDR is running 1 rig currently and has ~172 engineered net drilling locations. The Company has built the position relatively recently, adding ~39,000 net acres in 2013. Figure 77: MTDR Delaware Basin Acreage Source: Matador Resources Company Presentation MTDR has drilled two wells at the Ranger prospect where the Second Bone Spring looks to be the primary initial target. One of the wells is offsetting CXO s Stratojet 31 State #3H well which has cumulative production of 360 MBo and 426 MMcf in 24 months. This Ranger 33 State Com #1Hwell had a 24-hour IP of 619 Boepd (93% oil) and was producing over 700 Boepd after 60 days on artificial lift. There are also a number of successful 3rd Bone Spring wells in the region as well. Because the Bone Spring is a deltaic deposition, it may take time to delineate this position, and we think there is likely more geologic work to be done vs. the Wolf prospect further south. However, based on some of the nearby well results, this asset could generate very high-return drilling locations. Page 65 of 82

Figure 78: MTDR Ranger-Querecho Prospect Source: Matador Resources Company Presentation MTDR s Wolf prospect in Loving County, TX is prospective for horizontal Wolfcamp, which could be a consistent and scalable reservoir. The acreage position is surrounded by industry vertical wells and horizontal test wells, and activity is heating up currently. MTDR has drilled 1 well on the acreage and results could come in 1Q14. Figure 79: MTDR Wolf Prospect Source: Matador Resources Company Presentation Page 66 of 82

Occidental Petroleum (OXY- $88.00 - SP) OXY continues to rank as a leading operator in the Permian Basin, boasting a sizable acreage position, accelerating rig count and stable base of production that places OXY as the number one oil producer in the state of Texas. While bulk of production, approximately two-thirds, stems from the Company s core enhanced oil recovery program, the unconventional program should ramp significantly over the coming quarters and become a greater focus for OXY going forward. During the 3Q13 earnings call, management announced that it will be accelerated capital expenditures in the basin and has put in place a team dedicated to optimizing drilling and the acceleration of development in unconventional opportunities. In 2014, capital expenditures in the Permian Basin are expected to increase by $500 million to an estimated level of ~$2.4 billion, which will support the incorporation of four additional drilling rigs that will be dedicated entirely to horizontal development of the Wolfcamp, Wolfbone and Bone Spring in the Delaware Basin as well as the Wolfcamp in the Midland. Figure 80 depicts OXY s Permian acreage position relative to various plays while Figure 81 highlights OXY s gross and net exposure to select Permian Basin play types. Figure 80: OXY Acreage & Play Exposure Source: Occidental Petroleum Page 67 of 82

Figure 81: Select Acreage Counts Permian Basin Acreage Detail Source: Occidental Petroleum & Gross Net Delaware Basin: Avalon 340 120 1st Bone Spring 560 220 2nd Bone Spring 530 210 3rd Bone Spring 420 140 Wolfbone 210 70 Wolfcamp Shale 580 205 Delaware Shale 420 160 Penn Shale 320 120 Wabo 190 50 Yeso 230 60 Midland Basin: Cline Shale 390 160 Wolfcamp Shale 425 150 Wolfberry 280 100 Total 4,895 1,765 The shift towards horizontal development in the basin represents a change in strategy for the Company and we expect the unconventional development will continue to gain a larger role within OXY. Page 68 of 82

Pioneer Natural Resources (PXD - $172.73 - SP) PXD has a commanding acreage position in the Midland Basin with a total of ~900,000 relatively contiguous acres prospective for Spraberry and Wolfcamp zones, and the Company has been the clear leader in the play. The Company is the largest Spraberry/Wolfcamp producer and is currently running 28 rigs in the basin (13 horizontal). We divide PXD s Midland Basin acreage into northern and southern with the southern acreage consisting of Upton, Reagan, and Irion counties and the northern acreage primarily located in Midland, Glasscock, Martin, and Gaines counties. The southern acreage has been delineated with PXD inking a JV with Sinochem in 2013 while the more northern acreage is being proved up and the geographical extent being defined now. In the south, PXD has drilled ~90 horizontal Wolfcamp wells and is in the process of extending laterals and moving to pad drilling. The average per well IP rate is 1,241 Boepd, and PXD is running 8 gross horizontal rigs on the acreage. The Company signed a JV agreement with Sinochem in January 2013 for a 40% interest in PXD s 207,000 net acres in the southern Midland for total consideration of $1.7 billion. This deal values the acreage position at a discounted ~$17,500/acre (~$15,300/acre assuming $80,000 per flowing Bbl of production), and PXD retains the right to Spraberry zones. Further, the Company is generating better results recently and likely will continue testing additional Wolfcamp zones. Recently, PXD brought online an Upper B well which IP d at ~3,200 Boepd with 83% oil. The JV region average well has ~65% oil and ~90% liquids. We assume well costs of $7.5-8MM for 8,300 lateral wells, which use a combination of slickwater and hybrid fracs and drill in 28 days. PXD is estimating the average lateral length for 2014 wells could be 9,400. Figure 82: PXD Midland Basin Acreage Source: Pioneer Company Presentation Page 69 of 82

In the northern region of the Midland Basin, PXD s early horizontal results are even better, and the Company has ~600,000 gross acres prospective. Further, the Company has had success in three zones already: the Wolfcamp A, B, and D, and PXD is testing horizontal potential in the shallower Spraberry zones as well. Figure 83: PXD Appraisal Regional Focus Source: Pioneer Company Presentation To date, PXD has released data on 3 Wolfcamp B and 1 Wolfcamp A wells in Midland County, 2 Wolfcamp B wells in Martin County, and most recently, 4 Wolfcamp D wells in Martin, Midland, and Andrews counties. The Wolfcamp D IP rates ranged from 1,509 Boepd to 3,605 Boepd. The Wolfcamp B well with the most production data, the DL Hutt C #1H, has cumulative production of 170 MBoe in 9 months and is tracking a 1 MMBoe type curve. The Wolfcamp A well in Midland County has cumulative production of 115 MBoe in 5 months. To date, all three zones look highly prospective, although we are still uncertain of the areal extent of the play. We assume 800 MBoe EURs for 2 zones on all of PXD s northern Midland acreage in our NAV today. Page 70 of 82

QEP Resources (QEP - $30.84 - SO) QEP entered the Permian in December 2013, buying 6,700 Boepd of production and 47 MMBoe of proved reserves in Martin and Andrews counties for $950MM. The acreage has horizontal Wolfcamp prospectivity, and QEP s initial estimates include 9 potential horizontal target zones and 775 potential horizontal locations. QEP expects to grow production from the acreage to ~33 MBoepd in the next five years. Figure 84: QEP Permian Acreage Source: QEP Resources Presentation Page 71 of 82

Quicksilver Resources (KWK - $3.22 - SP) Quicksilver Resources has ~81,000 net acres in the Southern Delaware and Southern Midland Basins, including 36,000 net Midland acres in southern Upton and northern Crockett counties. This area is further west from where we have seen the majority of activity so we give minimal value for this acreage. On the Delaware Basin side, KWK has 45,000 net acres in Pecos, Reeves, and Jeff Davis counties. In November, KWK formed a JV with ENI over the Pecos County acreage where half of the acreage was sold for $52 MM, or $2,000/acre. The JV should provide for some wells to be drilled on the acreage, but it is further south than the development that we have seen to date in the basin. Figure 85: KWK Permian Acreage Source: Quicksilver Presentation Page 72 of 82

Range Resources (RRC- $86.15 - SP) While Range s primary focus remains concentrated in the Marcellus, the Company currently maintains a 100,000-acre position in the Midland Basin located primarily in Sterling and Glasscock counties. The Conger Field is predominantly held-by-production, 91%, and has potential for both Cline, Wolfcamp and Wolfberry development. Figure 86 depicts RRC s acreage in the Permian and highlights offset operator activity. Figure 86: Range Resources Permian Position Source: Range Resources Over the past several quarters, Range s activity levels have increased, but we do not anticipate an acceleration of activity as the Company has stated it will continue to take a wait and see approach, allowing other operators to take the lead. The Company is currently completing two 7,000 ft. lateral tests in the Cline and Upper Wolfcamp, with results likely to be provided during their 4Q13 earnings release in late February. In the vertical Wolfberry program, Range turned in line 14 wells to sales with an average 24 hr. IP rate of 370 Boepd, consisting of 203 Bbls/d of oil, 88 Bbls/d of NGLs and 475 Mcf/d of natural gas. Activity to date has been concentrated in Glasscock County with drilling costs reduced to $1.9mm per well. A recent well test in the eastern part of the acreage in Sterling County has Range now estimating the potential for up to 1,000 locations on 20 acre spacing. Ultimately we view this acreage as a divestible asset whereby proceeds generated by an asset sale could be reinvested in the Company s core Marcellus position in the Appalachian basin. RRC has announced that it has hired advisors to market a portion of the acreage and existing production. We estimate the asset package could generate proceeds of $550-$600 million. Page 73 of 82

Rosetta Resources (ROSE - $45.92 - FS) ROSE entered the Delaware Basin in March 2013, purchasing CRK s ~40,000 net acres in Reeves County for $768MM. The acreage lies in the heart of a region of significant industry activity today and is in the process of being de-risked horizontally by Rosetta and other operators. The Company s base case valuation assumes a vertical program with wells commingling from the top of the Bone Spring through the Middle Wolfcamp, but horizontal drilling provides substantial upside and results to-date look very encouraging. ROSE s existing production comes almost entirely from its very good Eagle Ford asset. Figure 87: ROSE Delaware Basin Acreage Source: Rosetta Resources Company Presentation ROSE is currently evaluating horizontal upside with 4 horizontal rigs running, but also testing ways to increase the base case vertical valuation. So far, the primary effort is to prove 20-acre spacing viability vs. the current assumption of 40-acre spacing. The Company has 1,500 vertical locations assuming 20-acre spacing with an average well costing $3.5MM. We assume a 250 MBoe type well in our valuation using 40-acre spacing over 75% of the acreage. The real substantial upside to valuation comes from horizontal drilling in multiple zones. To date, the Wolfcamp A has been tested on and around the acreage position and looks very encouraging so far. CRK drilled the Gaucho State #1H in the A zone on the eastern portion of the acreage position, which IP d at 1,134 Boepd and 76% oil. Recently, ROSE completed the Balmorhea 32-15 #1H further to the west, which IP d at 1,323 Boepd and 87% oil and had a 30-day rate of 737 Boepd. EGN recently announced the Bodacious #1H well, which is just offsetting ROSE s leaseline to the north this Wolfcamp A well IP d at 2,229 Boepd. Additionally, CXO has positive Wolfcamp A well results just to the east of ROSE s acreage, and other operators have had success to the south. Page 74 of 82

ROSE is moving quickly to test the horizontal potential of the acreage position. The Company recently announced a plan to run 4 horizontal rigs in 2014 and has laid out a horizontal development plan for the asset. While we do not yet have a horizontal type curve from ROSE, this could be coming in early 2014. Over time, the Company will likely test multiple Wolfcamp zones and possibly targets in the Bone Spring, which could provide very substantial inventory. Figure 88: ROSE Engineered Locations Source: Rosetta Resources Company Presentation ROSE is planning to drill 3 additional horizontal wells on the acreage this year with one at the eastern extent, one offsetting the original CRK Gaucho well, and the third further to the southwest. CXO is also planning a new well on the two companies shared acreage position to the north, offsetting EGN s Bodacious well. We will likely be hearing considerable dataflow around ROSE s position later this year and throughout 2014. Page 75 of 82

Royal Dutch Shell (RDS - $71.05 - FS) Shell entered the Permian through an acquisition from Chesapeake in 12of 618k net acres, primarily in the Delaware Basin. Despite an announcement in mid- 13 to market its U.S. liquids-rich shale acreage, RDS increased its Permian rig count through 13 and currently operates 8 rigs in the play. The Company is in development mode in the Bone Spring while the Avalon and Wolfcamp are considered exploration. Figure 89: Shell Delaware Basin Acreage Source: Shell Company Presentation Page 76 of 82

SM Energy (SM - $84.00 - SO) SM currently holds ~ 129,750 net acres in the Permian following its recently acquired 32,500 net acres in Dawson & Gaines counties. The Company s acreage spreads throughout the Midland Basin with ~19,000 net acres in the core of the Play in Upton County, another 53,500 net acres in Gaines and Dawson counties, 54,500 net acres in Borden and Garza counties, and a small position in the Delaware Basin in SE New Mexico. The Permian has been an increasing focus for the Company as it now accounts for ~5% of SM s 3Q13 production. However, both production and CAPEX spending significantly lag behind the Company s core Eagle Ford and Bakken positions. With the recent sale of the Company s Anadarko Basin assets behind them, we think the Company will be increasing CAPEX dollars in the Permian in 2014 and beyond as management has stated that they believe the Permian will be third leg of the Company s operational portfolio moving forward. Figure 90: SM Permian Midland Acreage Source: SM Company Presentation SM s best acreage positions in the Permian are its Sweetie Peck and Halff East Fields in Upton County where the Company recently drilled its best Wolfcamp B well to date, the Dorcus 3035H, that achieved a 30-day IP rate of 1,226 Boepd (82% oil) with a ~5,000 lateral. In addition the Company recently announced 2 more Upton County Wolfcamp B tests which achieved 24-hr IP rates of 1,162 Boepd (83% oil) and 1,259 Boepd (81% oil). While, SM has not been as active in its Upton County acreage as some offset operators such as FANG and PXD, the Company s recent well results along with the near 100% success rates in the HZ Wolfcamp B achieved by offset operators, essentially de-risk the 2 Upton County fields for SM. The real driver for SM moving forward in the Permian will be the successful development of its more northern acreage where the Company holds the majority of its Permian position. SM has been the most active operator in the Garza/Borden counties area to date drilling mostly Cline and Mississippian wells with varying degrees of success. We do not expect the Company to keep drilling this acreage in 2014 as it recently completed two wells in 3Q13 that did not meet its expectations. We believe the Company will start to focus on higher return acreage positions both in the Permian and in its other basins. Page 77 of 82

In the Company s more southern Buffalo field, SM is currently planning to spud its first Wolfcamp B well in 4Q13 on the Gaines/Dawson County border. Industry activity has certainly been increasing in the northern portion of the Midland primarily in Martin and Andrews counties and it appears those counties can deliver economic wells. Activity in the Dawson and Gaines counties area is much lower than in Martin and Andrews; however, a successful test from SM and offset operators such as FANG could spur additional activity. If SM can successfully develop the Wolfcamp and or the Clearfork and Spraberry in its Buffalo acreage it will be a real boon for the Company as it currently holds ~53,500 net acres in the area. SM s smallest acreage position in the Permian is in its New Mexico PDU/ESDU field, which is prospective for the Bone Spring formations. The Company has been actively drilling the acreage having drilled 2 Bone Spring wells in 3Q13 however if the Company does not increase its acreage position from its current 2,700 net acres this play will not be a real needle mover for a Company the size of SM. SM s recently announced that ~9% of the Company s ~$1.66B drilling and completion budget for 2014 will focus on the development of the Permian Basin with majority of the remaining budget targeting the Eagle Ford (54%) and Bakken (21%). SM plans to operate ~2.5 HZ rigs for the year focusing on the Wolfcamp in its Sweetie Peck Field in Upton County and its Buffalo Field in Dawson & Gaines counties. Page 78 of 82

W&T Offshore (WTI - $14.99 - SP) W&T Offshore has built a ~25,730 net acre position in its Yellow Rose prospect in the Midland Basin through various acquisitions and divestitures since 2011. Its current position is in the northern portion of the basin in Gaines, Dawson, Andrews, & Martin counties has experienced increased horizontal industry activity of late. The Permian now comprises ~9% of WTI s current daily production at ~4,000 Boepd and the Company is working to grow that figure as it continues to develop its acreage. Figure 91: WTI Acreage Position & Offset Operator Wells Source: WTI Company Presentation WTI is currently running 2 rigs at Yellow Rose, developing the acreage on 80 & 40-acre vertical spacing. The Company estimates it could potentially have ~860 vertical drilling locations in its acreage when factoring in full 40 & 20-acre spacing. The primary target for the vertical program is the Wolfberry trend at 11,000 13,000 where WTI s 3Q13 completions yielded an average 30-day IP rate of 97 Bopd. In addition, the Company is also awaiting results of its first HZ Wolfcamp B well that will be its 7 th horizontal well to date with the other 6 targeting the Wolfcamp A formation. Assuming the Company is successful in its first Wolfcamp B test; W&T plans to continue testing the zone in 2014 along with potentially either the Wolfcamp D or the Spraberry. While the Permian is not a chief focus for the Company due to its successes offshore, WTI s acreage position has seen a significant increase in activity recently by offset horizontal operators like FANG and PXD targeting not only the Wolfcamp but also the Clearfork and the Spraberry. We see this as a great opportunity for W&T to pursue a fast follower strategy in the play and allow the other operators to do much of the testing which we believe could improve future production rates for W&T when it does decide to drill more horizontal wells. Page 79 of 82

Whiting Petroleum (WLL - $58.10 - FS) WLL has ~73,000 net acres in the Company s Big Tex prospect in the Delaware Basin prospective for vertical Wolfbone and horizontal Wolfcamp drilling. The acreage lies in Pecos, Reeves, and Ward counties. The Company has released several initial horizontal wells with IP rates ranging from 440 Boepd to 674 Boepd. The Company is experimenting with well design now using more proppant and cemented liners. WLL inked a deal to sell ~32,000 net acres in 4Q13 for $150.1MM. We view the Permian position as non-core to WLL today as the Company is more focused in the DJ Basin, and we would not be surprised to see additional Permian sales in the future. Figure 92: WLL Permian Acreage Source: Whiting Company Presentation Page 80 of 82

Appendix A: Important Disclosures Analyst Certification We, David Amoss, Blaise Angelico, Joseph Bachmann, Brian Corales, Blake Fernandez, Alonso Guerra-Garcia, K. Blake Hancock, Peter Kissel, Holly Stewart, Philip Stuart Richard Roberts and Bill Sanchez, certify that the views expressed in this research report accurately reflect our personal views about the subject securities or issuers; and we, David Amoss, Blaise Angelico, Joseph Bachmann, Brian Corales, Blake Fernandez, Alonso Guerra-Garcia, K. Blake Hancock, Peter Kissel, Holly Stewart, Philip Stuart, Richard Roberts and Bill Sanchez, certify that no part of our compensation was, is, or will be directly or indirectly related to the specific recommendation or views contained in this research report. Important Disclosures This report was prepared by a Research analyst. is a Division of Scotia Capital (USA) Inc., a US Registered brokerdealer and a member of the New York Stock Exchange and FINRA. 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All pricing of securities in reports is based on the closing price of the securities principal marketplace on the night before the publication date, unless otherwise explicitly stated. Scotia Capital (USA) Inc. is a multidisciplined financial services firm that regularly intends to seek investment banking business with companies covered in its research reports, and thereby seeks to receive compensation from these companies for services including, but not limited to, acting as an underwriter in an offering or financial advisor in a merger or acquisition, or serving as a placement agent for private transactions. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. For applicable current disclosures for all covered companies, please write to the Research Department at the following address: Research Department 1100 Poydras Street, Suite 3500 New Orleans, Louisiana 70163 Definition of s Equity Research Ratings & Risk Rankings Prior to January 7, 2013, utilized a rating system of Focus List Stock (FS), Market Outperform (MO), Market Perform (MP), Market Underperform (MU) and Rating Suspended (RS). Click here to view definitions. We have a four-tiered rating system, with ratings of Focus Stock, Sector Outperform, Sector Perform, and Sector Underperform. Each analyst assigns a rating that is relative to his or her coverage universe or an index identified by the analyst that includes, but is not limited to, stocks covered by the analyst. Our risk ranking system provides transparency as to the underlying financial and operational risk of each stock covered. Statistical and judgmental factors considered are: historical financial results, share price volatility, liquidity of the shares, credit ratings, analyst forecasts, consistency and predictability of earnings, EPS growth, dividends, cash flow from operations, and strength of balance sheet. The Director of Research and the Supervisory Analyst jointly make the final determination of all risk rankings. The rating assigned to each security covered in this report is based on the Scotiabank, Global Banking and Markets research analyst s 12-month view on the security. Analysts may sometimes express to traders, salespeople and certain clients their shorter-term views on these securities that differ from their 12-month view due to several factors, including but not limited to the inherent volatility of the marketplace. Ratings Focus Stock (FS) The stock represents an analyst s best idea(s); stocks in this category are expected to significantly outperform the average 12-month total return of the analyst s coverage universe or an index identified by the analyst that includes, but is not limited to, stocks covered by the analyst. Sector Outperform (SO) The stock is expected to outperform the average 12-month total return of the analyst s coverage universe or an index identified by the analyst Risk Rankings Low Low financial and operational risk, high predictability of financial results, low stock volatility. Medium Moderate financial and operational risk, moderate predictability of financial results, moderate stock volatility. High High financial and/or operational risk, low predictability of financial results, high stock volatility. Page 81 of 82

that includes, but is not limited to, stocks covered by the analyst. Sector Perform (SP) The stock is expected to perform approximately in line with the average 12-month total return of the analyst s coverage universe or an index identified by the analyst that includes, but is not limited to, stocks covered by the analyst. Sector Underperform (SU) The stock is expected to underperform the average 12-month total return of the analyst s coverage universe or an index identified by the analyst that includes, but is not limited to, stocks covered by the analyst. Other Ratings Tender Investors are guided to tender to the terms of the takeover offer. Under Review The rating has been temporarily placed under review, until sufficient information has been received and assessed by the analyst. Speculative Exceptionally high financial and/or operational risk, exceptionally low predictability of financial results, exceptionally high stock volatility. For risk-tolerant investors only. Ratings Distribution As of 12/31/2013, has 131 companies in its coverage universe. Of the 131 securities under s coverage universe, 131 carry a recommendation. The percentages referenced below are based upon the 131-rated securities in the coverage universe. 61% have been assigned a Focus List (FS) or Sector Outperform (SO) rating. Within the last 12 months, 58% of companies with this rating are investment banking clients of the Firm. 39% have been assigned a Sector Perform (SP) rating. Within the last 12 months, 37% of companies with this rating are investment banking clients of the Firm. 0% have been assigned a Sector Underperform (SU) rating. Within the last 12 months, 0% of companies with this rating are investment banking clients of the Firm. For the purposes of the ratings distribution disclosure FINRA requires members who use a ratings system with terms different than buy, hold/neutral and sell, to equate their own ratings into these categories. Our Focus Stock, Sector Outperform, Sector Perform, and Sector Underperform ratings are based on the criteria above, but for this purpose could be equated to strong buy, buy, neutral and sell ratings, respectively. Valuation / Risk Factors Valuation Method Used to Determine Price Target: Our current price targets for the Exploration and Production sector are based on a multiple of net asset value (NAV), which is determined by our evaluation of the following: reserves (proven, probable and possible), growth rate, drilling inventory, discounted cash flow (DCF), historical performance and our assessment of management. Risk Factors Which May Impede the Achievement of the Price Target: (1) Industry fundamentals with respect to customer demand or product/service pricing could change and adversely impact expected revenues and earnings; (2) issues relating to major competitor or market shares or new product expectations could change investor attitudes toward the sector or the stock; (3) Unforeseen developments with respect to the management, financial condition or accounting polices or practices could alter the prospective valuation; or (4) external factors that affect the U.S. economy, interest rates, the U.S. dollar or major segments of the economy could alter investor confidence and investment prospects. Oil and Gas Prices and OPEC: Financial and operating performance for companies in the Energy industry are affected by absolute and relative changes in oil and gas prices, which are influenced by a multitude of regional, national and global factors. As such, future stock price performance may also be influenced by such factors associated with changes to fiscal and royalty regimes in countries where it operates, or might operate, the potential for geopolitical upheaval (given its global presence) and may face various technical and operational risks associated with the products and services it provides. Agreements among OPEC members, including production limitations, may also affect worldwide commodity prices and financial and operational performance for companies in the Energy industry. Analysts Compensation The compensation of the research analyst who prepared this report is based on several factors, including but not limited to, the overall profitability of Scotiabank, Global Banking and Markets and the revenues generated from its various departments, including investment banking. Furthermore, the research analyst s compensation is charged as an expense to various Scotiabank, Global Banking and Markets departments, including investment banking. Research Analysts may not receive compensation from the companies they cover. Additional Disclaimers and Disclosures Opinions expressed are subject to change without notice and do not take into account the particular investment objectives, financial situation or needs of individual investors. Employees of Scotia Capital (USA) Inc. or its affiliates may, at times, release written or oral commentary, technical analysis or trading strategies that differ from the opinions expressed within. This email may be considered advertising under federal law. If you decide not to receive Research via email, please reply to howardweil@howardweil.com and ask to be removed. Additional information is available upon request 1100 Poydras Street, Suite 3500, New Orleans, LA 70163 1.800.322.3005 Page 82 of 82