Deutsche Bank

Deutsche Bank Markets Research United States HY Corporate Credit Energy HY E&P Sector Update & 2015 Outlook Quarterly Updates for E&Ps under coverage including: In•Depth Relative Value Forecasts Sector Benchmarking Scenario Analysis E&P Universe Credit and Operational Metric Screen across 30 credits including: Results and Ranking Snapshot Scatter Plots by Metric Liquidity Analysis Scenario Analysis Historical Financial Summaries Selected Recommendations: BUY EXCO Resources (XCO) BUY Cimarex (XEC) BUY Halcon Resources (HK) BUY Hilcorp Energy I (HILCRP) BUY Newfield (NFX) BUY Range Resources (RRC) SELL Denbury Resources (DNR) Recommendation Changes: HOLD Chesapeake Energy (CHK) from BUY SELL Forest Oil/Sabine (FSTO) from HOLD SELL QEP Resources (QEP) from HOLD SELL SandRidge (SD) from HOLD SELL Samson Resources (SAIVST) from BUY E&P Screening and Analysis for the American Energy Permian (AEPB) Antero Resources (AR) Bonanza Creek (BCEI Chesapeake (CHK) Cimarex (XEC) Concho Resources (CXO) Danbury Resources (DNR) Diamond Back Energy (FANG) EP Energy (EPE) Exco Resources (XCO) Forest Oil/Sabine (FSTO) Halcon Resources (HK) Hilcorp Energy (HILCRP) Magnum Hunter Resources (MHR) Midstates Petroleum (MPO) following E&Ps: Newfield (NFX) Oasis Petroleum (OAS) Parsley Energy (PE) Penn Virginia (PVA) QEP Resources (QEP) Range Resources (RRC) Rosetta Resources (ROSE) Samson Resources (SAIVST) Sanchez Energy (SN) SandRidge (SD) SM Energy (SM) Triangle Petroleum (TLW) Tullow Oil (TLW) WPX Energy (WPX) Date 13 January 2015 Kathryn O'Connor Research Anent Jaloci Research Associate VA Deutsche Bank Securities Inc. DISCLOSURES AND ANALYST CERTIFICATIONS ARE LOCATED IN APPENDIX 1. MCI IP) 148/04/2014. EFTA01097655 13 January 2015 HY Corporate Credit Energy 3 HY E&P Sector Overview: Sifting through the carnage E&P Credit Screens and Analysis E&P Credit & Operational Metric Screen Overall E&P Screen: Results and Ranking Snapshot Leverage Screen Current PV-10 to 2016 Debt Screen Liquidity Screen Hedging Screen Adjusted Cash Margin Screen Commodity Mix Screen Conclusion: E&P subsector weighting: Maintain Underweight DB Commodities Price Deck & Outlook E&P Industry Relative Value Sheets Quarterly Updates for E&Ps under coverage Chesapeake (CHKI Cimarex (XEC) Denbury Resources (DNRI Exco Resources IXCO) Forest Oil/Sabine (FSTO) HaIcor) Resources (HK) Hilcorp Energy (HILCRP) Newfield (NFX) QEP Resources (QEP) Range Resources (RRC) Samson Resources (SAIVSTI SandRidge (SD) Financial Summaries and Sensivities for Non-covered E&Ps American Energy Permian (AEPBI Antero Resources (AR) Bonanza Creek (BCEI Concha Resources (CXO) Diamond Back Energy (FANG) EP Energy (EPEI Lightstream Resources (LTSCN) Magnum Hunter Resources (MHRI Midstates Petroleum (MPO) Oasis Petroleum (OAS) Parsley Energy (PE) Penn Virginia (PVA) Rosetta Resources (ROSE) Sanchez Energy (SN) SM Energy (SM) Triangle Petroleum (TLW) TuIlow Oil (TLW) WPX Energy (WPX) 18 20 23 26 28 32 35 39 41 42 46 54 60 66 72 77 82 87 92 97 102 107 112 118 120 122 124 126 128 130 132 134 136 138 140 142 144 148 150 152 154 Page 2 Deutsche Bank Securities Inc. EFTA01097656 13 January 2015 HY Corporate Credit Energy HY E&P Sector: Sifting through the carnage Oil price collapse - how did we get here? Looking back, oil fundamentals at the recent peak in the June/July 2014 timeframe were seemingly decent. Despite some volatility, discussions with E&P management teams were bullish in the face of increasing service costs, and capex budgets looked to be rising as higher than anticipated oil prices drove greater than expected cash flow. On the geopolitical side, we had rising tensions in the Middle East posing a headwind for OPEC supply (driver of a majority of future OPEC supply growth). Further, M&A chatter was relatively strong after the Whiting (Will/Kodiak (KOG) acquisition announcement. In summary, there were few reasons the market had to be concerned about the sector. Fast forward six months and the world has changed, leaving investors to ask the question, "how did we get here?" Looking through the wreckage now, it does seem that there were missed signs that when taken to together pretty clearly mark how we reached our current oil destination (WTI trading at less than $50). From 2002 to 2012, global demand growth averaged over 1.1 million b/d while non-OPEC supply growth averaged only 560 Kb/d; this excess demand supported a generally increasing oil price. That trend reversed itself starting in 2013 as average global demand fell below 1.0mmb/d at the same time non-OPEC supply growth accelerated to an average of t6 million b/d. Specifically and more dramatically in 2014, the difference between incremental annual world demand growth and non-OPEC supply growth gapped out to an oversupply of 1.2 million b/d - a differential not witnessed in decades (Figure 1). This was the backdrop as OPEC met on November 27th and decided to maintain its ceiling production level of 30.0 million b/d. Figure 1: World Oil Demand and Non-Opex Supply Growth 2000 1800 1600 1400 - 1200 1000 - 800 600 - 400 • 200 - 0 12014E &wet BA a DB arntnAta •World demand growth (kbd) Total non-OPEC supply growth (kbd) 2015E I. [ 2019E 2020E I I Looking at the individual pieces of this story, the current outcome now seems like a reasonable one. Anecdotally, North American E&Ps had seen a relatively steady pattern of hitting production guidance if not beating - and raising - through the Q2 14 earnings season and eventually the Q3 reporting season. This came despite some tough weather to start off the year. Looking at the Deutsche Bank Securities Inc. Page 3 EFTA01097657 13 January 2015 HY Corporate Credit Energy demand side of the equation, there was a key difference in expected demand momentum as we moved through 2014 versus 2013 (Figure 2). While in 2013 there was a relatively slow but largely steady improvement in expected demand through the year, 2014 started strong but saw a marked deterioration in expected demand that started in August but declined precipitously as we moved through year-end. These two factors left a bit of a perfect storm for oil in and around the time of the OPEC meeting. While analysts were somewhat split on the expected specific outcome, a majority expected an OPEC production cut of some sort to help stem oil oversupply (9 out of 13 street analysts polled by Reuters). All of this led to a dramatic move in oil when OPEC decided to maintain the current 30.0 million b/d ceiling production without even a minor cut, which was seemingly the market's last chance to stabilize oil prices. Worse, all of this played out against an actual OPEC average production level 30.2 million b/d YTD through November 2014; the whisper production for December is 30.7 million b/d — and that includes lower Libyan production. Figure 2: Global Demand Growth Expectations Over Time mb/d 1.5 1.4 1.3 1.2 1.1 1.0 0.9 0.8 0.7 0.6 2013 — — 2014 2016 • I4LL4• • 7 7 IT 2 4. asc• • • • • • S. • 0' ro co 7 co e) m co 7 7 # C Sane! 'EA 08 Cooly Absturcet 7 IP V, I—a RI Oil looking forward - Are we there yet? The simple answer is no. Despite the significant amount of pain inflicted already, unfortunately, we believe there is likely more to come in 2015. Excluding the 2008/2009 (which was even more extreme), the average sell-off in an oil bear market reached its nadir with an average decline of 500/0 from the peak over a 15-month period (Figure 3). Currently, we have observed —60% decline in oil prices from the peak; however, we are only 7 months into this episode. Interestingly, of the four episodes shown, the one where oil reached its low point in the shortest amount of time was in 1986 - the historical data point that sets up the most like current scenario; in that case, OPEC too played a significant role in the 1986 oil bear market. However, at that time, it was other OPEC producers that were squeezing out marginal Saudi Arabian barrels. This time the US is playing the role of Saudi/OPEC spoiler by growing its unconventional production base and squeezing out OPEC barrels. In any case, despite a significant decline in oil prices so far, we don't see any expected changes to the major drivers of oil price in the near term. Page 4 Deutsche Bank Securities Inc. EFTA01097658 13 January 2015 HY Corporate Credit Energy IFigure 3: Prior Bear Markets in Industrial Commodities Commodity Stan End Duration, mo Drawdown, % Oil 11/2211985 07/25/1986 8 -56 Oil 10/18/1992 12117)1993 14 -37 Oil 01/10/1997 12/11/1998 23 -58 Oil 11/24/2000 01/1812002 14 -48 Nat Gas 10/24/1997 08/28/1998 10 -52 Nat Gas 04)06/2001 01/25/2002 10 -61 Nat Gas 06110/2011 04/13/2012 10 -60 Aluminum 08126/1988 02/02/1990 18 -45 Aluminum 08118/1995 03/12/1999 43 -38 Copper 08121/1992 10/22/1993 14 -37 Copper 08121/1995 02/22/1999 43 -54 Iron Ore 08126/2011 09/07)2012 13 -50 Avg for oil 15 -50 Avg tor all 18 -50 Current episode Oil 06/20/2014 01/10/2015 7 -54 Aluminum 04/29/2011 01/10/2015 45 -36 Copper 07/29/2011 01/10/2015 42 -35 Iron Ore 12/062013 01/10/2015 13 -49 Sane oe Oral' $ea411Y While recent oil downturns have had a relatively quick "V" shaped recovery, we do not believe that this will be the case this time. We believe recent more episodes (97198, 08/09) were reflective of more general market improvements and a retum to functioning capital markets (post the Russian default and post the financial crisis, respectively). These overall market recoveries, while important to oil, particularly the demand side, were somewhat outside direct, physical oil markets. Where this bear oil market is concerned, we don't see a quick macro event outside of physical oil markets as the panacea or quick fix. Rather, we are looking for a more "U" or "L" shaped recovery for oil. In 1986, again, oil priced quickly raced to the bottom over an 8-month period, but then, excluding the first Iraq war, took about 14 years to recover. To be clear, we are not making that extended recovery call here because we do believe that there were anomalies to the 1986 case. One anomaly being the 1986 Tax Reform Act and its net effect on overall US GDP, which according to the World Trade Organization, would normally have seen a greater positive effect from lower oil. However, even looking at the more "normalized" oil recoveries listed (excluding 1986 and 2009), it took oil anywhere from 11 to 26 months to return to its previous peak, leading to an average 17-month oil "recovery" time. Importantly, we acknowledge that markets are forward looking, and therefore believe that a change in sentiment itself could likely precede the actual improvement in oil, and also energy-related securities. We focus here on those data points that could improve the market mentality around oil. Note: we discuss the expected recovery cycle for high yield energy bonds specifically later in this outlook. Deutsche Bank Securities Inc. Page 5 EFTA01097659 13 January 2015 HY Corporate Credit Energy IFigure 4: Oil Supply-Demand Forecast 2013 2014e Nov-14 2015e 2016e 2014/13 2015(14 2016/15 2015/Nov-14 Consideratations OECD 46.1 45.6 45.6 45.5 -0.5 0.0 -0.1 US vs Europe GDP outlook Non-OECD 45.7 46.8 47.8 49.3 1.1 1.0 1.4 How resilient is China demand? Oil Demand 91.7 92.4 93.4 94.8 0.7 OS 1.3 Will lower oil price prompt upgrades? US 10.2 11.7 12.7 13.3 1.5 1.0 0.7 Pace & magnitude of supply response Other non.OPEC 44.4 44.8 45.1 45.5 0.4 0.3 0.6 Risk of delays, disruption & capex cuts Non-OPEC Supply 54.6 56.5 57.8 58.8 1.8 1.3 13 OPEC NGLa 6.3 SO 6.7 6.8 0.1 0.3 0.1 Libya 0.9 0.4 0.7 0.7 0.9 -0.5 0.3 0.0 0.0 Is there further downside supply? Iran 2.7 2.8 2.8 2.8 2.8 0.t 0 0.0 0.0 Possibility of mid-15 nuclear deal Iraq 3.1 3.3 3.4 3.4 3.3 0.2 0.1 0.0 0.0 Other 24.2 23.2 23.4 22.0 22.5 -t.0 -1.2 -0.3 -1.4 Will Saudi add supply if non-OPEC falls? Cell on OPEC 309 29.5 30.3 28.9 292 -1.4 -0.6 -0.3 -1.4 1.4mb/d reduction needed vs Nov-14 &wet De teary Sanwa, Looking at this simplified supply and demand outlook for oil sums up our thoughts on a longer term recovery. Given no expectation for a call on OPEC in 2015, we believe oil prices will persist at lower levels through 2015, especially in 1H 15 as the market is currently 1.4 million b/d oversupplied. The basic levers that could improve the supply and demand dynamics in the next year are the following in our minds: (i) better than expected economic growth (ie demand), (ii) more volatile seasonal weather patterns, (iii) faster than expected Non-OPEC production declines, (iv) a sooner-than-scheduled OPEC meeting (June currently), (iv) a sooner than scheduled OPEC meeting (June currently), or (v) unexpected geopolitically -related production declines. IFigure 5 GDP Forecast & Revision (% yoy) Forecast level Dec' 14 WO 2019E 2015E 2015E Forecast change since Sep' 14 WO' 2019E 2015E 2018E G7 1.8 2.5 2.4 -0.1 0.0 0.0 US 2.4 3.5 3.1 0.1 0.1 -01 Japan 0.5 1.4 1.6 -0.6 0.1 0.2 Euro area 0.8 1.0 1.3 0.0 -0.1 -0.1 Asia (ex-Japan) 6.0 6.2 6.1 -0.3 -0.7 -0.7 China 7.3 7.0 6.7 -0.5 -1.0 -1.3 India 5.5 6.5 6.5 0.0 0.0 0.0 EEMEA 2.3 1.9 2.5 0.4 -0.8 -0.4 Russia 0.5 -0.9 -0.4 0.0 -1.9 -1.8 Latin America 0.8 1.5 2.9 -0.2 -0.6 -01 Brazil 0.1 0.7 t.9 -0.2 -0.5 0.0 Advanced economies 1.7 2.4 2.3 0.0 0.0 0.0 EM economies 4.4 4.5 4.9 -0.2 -0.7 -0.6 Global 3.2 3.6 3.8 0.0 -0.3 -0.2 Sane Oni ft:Oe &Pat tco,tvwci Noe 'Sommer( OWN Onto* losakus Are torn ma% caned lamp Orrobei nfOPPP *arts Page 6 Deutsche Bank Securities Inc. EFTA01097660 13 January 2015 HY Corporate Credit Energy First, we look at the demand side. Looking at what our economics team is expecting for 2015, it is clear that despite the drop in oil prices (and its positive follow-on effects for certain economies), expected global growth trends have seen a notable decline over the last quarter of 2014. This is evidenced by the deceleration of expected growth reflected in our estimates, especially in Asia. The main drivers of the downgrades are driven "entirely by markdowns to emerging market growth prospects, which were reduced by more than 1/2 percentage points over the next two years. These downgrades were broad- based across regions, with three of the BRICs, Russia, China, and Brazil (in that order) recording the largest and most important downward revisions. Most important is the downward revision to China, where we now see increased negative spillover from past overinvestment in property and the government focused on a more sustainable 7% rate of growth. Global growth is expected to bottom at a relatively subdued rate of 3.2% in 2014 and rise slowly over the next two years." We see little possible upside here, and in fact, believe there could be further downside to global demand. Next, we look at the seasonality of oil and the possibility for more volatile seasonal weather patterns. Historical and expected oil demand seasonality is reflected in Figure 6 on the left. In the chart on the right, we overlay DB's quarterly demand/non-OPEC supply projections holding OPEC production flat at the October 2014 level (30.6 million b/d). Looking at Figure 7, one can see that the magnitude of the expected level of oversupply (1.5 million b/d in 1H 15) is well above historical averages. While many would look to Libya as the inevitable OPEC producer most likely to decrease production given recent unrest, even assuming no production from Libya, DB estimated excess oil supply in 1H 15 would still be 0.7 million b/d. This would leave the market needing a significant and unlikely change in weather to absorb excess supply in 1H 15. For example, last year a colder-than-normal winter increased seasonal demand by —250-300K b/d. On the margin, we see the seasonal demand effects of oil as well as marginal economics (discussed below) as a key reason for sub-S50/bbl oil at least through 1H 15. Figure 6:1 H Global Crude Demand Typically 1 Million b/d less than FY LON 1400 140 0 400 4400 -1400 Seasonality typically means that III demand is —1mb/d below the FY avg. • 2011 Sauces LA Di t Etonorna 01 02 CO 01 *2012 •201.1 420W0 42010. Figure 7:2015 Will Require Market to Absorb >Normal Seasonal Excess ton 1.000 000 1)00 400 4,500 4.000 4.500 Sam*counter seasonal move In stocks/other m 2H14 to absorb over-supply If we assume NO reduction In OPEC supply Vs 4014 pressue to absorb peaks In 2Q15 with larger than normal IH stock build required Oi a to ea •201I ann 52013 salll. noise D (ecotone* Moving onto supply, we look at Non-OPEC production. For purposes of this discussion, we are talking largely about US production growth as markets (and OPEC) are now looking towards the US for a supply response (i.e. significant reduction in annual oil growth). However, we do not think that supply response will be one readily observed in 2015 largely due to (i) a significant inventory of drilled but uncompleted wells (up to 6 months of inventory per producer), (ii) a relatively high level of hedging in 2015 (less so in 2016), (iii) the ability to high grade to the most economic plays, (iv) recently achieved drilling Deutsche Bank Securities Inc. Page 7 EFTA01097661 13 January 2015 HY Corporate Credit Energy efficiency, and (v) decreasing non-productive capital spending (test wells, seismic, infrastructure, etc). As we consider 2016, our equity counterparts have looked at the issue of US growth and asked the question: "What would we need to see from the industry to normalize production growth from 2016 forward at a level more consistent with demand expectations? (i.e. reduce US YoY supply growth to 500-600 Mb/d)." They estimate "that at minimum, the industry would need to drop —160+ horizontal rigs from the "Big Three" plays (Bakken, Permian, Eagle Ford) - or -25% of the near 700 rigs currently operating in these plays. The implications for the overall oil rig count (-1,600) is much more severe, as vertical rigs and marginal plays would likely fall off first, implying a total rig cut of 500+." If this scenario plays out as expected, it suggests that US YoY supply growth would be reduced from 0.90.1.0 million boepd now to about 500-600K boepd, or a reduction of 300-400K boepd. We believe markets would view this move as significant. Looking at Figure 8, the good news is that we have seen some solid progress towards decreasing horizontal rigs by that —160 figure. Since the OPEC meeting in late November, horizontal rig count in the Big Three plays has decreased by 40 rigs or about 25% of the DB required cut - and the biggest step down came in this past week. In that same span, total US rig count has decreased by 167 rigs or about 33% of the DB required cut - again, with the best step down coming this past week. Not surprisingly, the necessary decline in less efficient rigs (both vertical rigs and rigs in marginal plays) is happening faster than for the core three plays, where rigs are most efficient. I Figure 8: US Drilling Rig Score Card Since November OPEC Meeting Total Rigs Across All Basins Directional Horizontal Vertical Total Rigs working as of OPEC Meeting 194 1,371 352 1,917 12/5/2014 WoW change 4 (3) 2 3 12/12)2014 WoW change 121 (II (24) 127) 12719/2014 WoW Mange Ill 111l (6) 118) 12/26/2014 WoW Mange (141 161 (15) 135) 1/2)2015 wow change (61 (141 19) 129) 1/9/2015 WoW change (141 (351 (12) 161) Rigs working as Week 1/9 161 1,301 288 1,750 Total Rig Decline since OPEC Meeting (11/27) (33) (70) (64) (167) Total Rig Decline since Relative Oil Peak 16/20) (671 51 (92) (108) Horizinal Rig Decline in the Big 3 Plays Eagle Ford Permian Bakken Total Riga working ea of OPEC Meeting 207 363 189 769 12/5/2014 WoW change 131 4 (3) (2) 12712/2014 WoW change 121 171 (1) 110) 12/19/2014 WoW change 2 4 (7) (1) 12/26/2014 WoW change 121 3 (2) (1) 1/2/2015 WoW change (51 0 0 (5) 1/9/2015 WoW change 131 (101 (8) 121) Rigs working as Week 1/9 194 357 168 719 Big 3 Rig Decline since OPEC Meeting (11/27) 1131 (61 (21) (40) Big 3 Rig Decline since Relative Oil Peak (6/20) 10 (34) 7 117) Savo. Bab/ I& Page 8 Deutsche Bank Securities Inc. EFTA01097662 13 January 2015 HY Corporate Credit Energy Beyond these initially positive data points on lower rig count, there are upside supply risks in the form of high grading and drilling innovation. The natural gas playbook has shown us that producers across the board have proven to be innovative during price dislocations like the one we are currently experiencing. Over the past several years, the path of continued drilling improvement has been the norm for producers. While some plays are further along the innovation road (Bakken, Eagle Ford) than others, we believe the current environment will only incentivize producers to push for further process improvements; we should continue to see more production with less capital. That said, as producers narrow their focus and look to high grade to only the top plays (Permian), other relatively less attractive plays like the Bakken and Eagle Ford will see drilling dollars move out. One can see this above where Permian horizontal rig count has gone down by just 6 rigs since the OPEC meeting, and Bakken and Eagle Ford horizontal rig count has declined by 21 and 13 rigs, respectively. The offset to the high grading and efficiency points would be an inability to regain momentum. Producers have also done an excellent job maintaining momentum over the past several years by securing low cost capital, protecting cash flows with hedges and innovating operationally; prolonged, depressed oil prices will eliminate two of those levers for a time, limiting how and where E&Ps can allocate spending dollars most efficiently to generate an acceptable return. Moving on to OPEC, when looking at the recent non-action with our energy hat on, it clearly shows OPEC, and really Saudi Arabia's, intention to maintain market share in the long term. It plainly had two decisions - either let higher cost Non-OPEC oil growth continue to encroach and likely accelerate over time, or take a stand to undermine Non-OPEC supply now before it became a bigger threat. The OPEC decision does indeed make sense on a stand-alone basis, but there are a couple other "ancillary" benefits to OPEC/Saudi Arabia including inflicting pain directly on both Iran and Russia through lower export revenues. Pressuring Russia further benefits Saudi Arabia as Russia will be a weaker supporter of Iran, its most significant rival in the region. Given that Saudi Arabia has about twice the level of govemment assets Russia does (on an annual basis: government assets divided by budget deficit), it can afford to withstand a low-price oil environment for longer to protect its long-term market share. Figure 9: US Onshore Oil Breakeven Economics ▪ 00 a LON 350) 3," • 410 • $(0421 $41.170 - MOS VS SO) • 20 US • S32$90 •1%599 3>1% ?MO ?MO 1270 110 5,0 i Sweet Wood illakania; DB Equey Rtrakarch 2014 1 mr in* Wood Mackenzie has done analysis to show the medium to long term breakeven economics of US unconventional crude supply (above). It clearly shows that a majority of US unconventional plays break even in the S65-70/bbl Deutsche Bank Securities Inc. Page 9 EFTA01097663 13 January 2015 HY Corporate Credit Energy area. It is important to keep those levels in mind when considering OPEC's next move. In order to inflict maximum damage to base US production, oil prices need to stay below long term breakeven levels for a sustained period of time. On the flip side, US E&Ps will do what they can in the short term to side- step a permanent momentum shift in their core plays. As we have seen, oil prices are slowly converging on this short-term, US unconventional "marginal" cost ($15-30/bbl range, discussed later). Taking all this together, we do think OPEC is prepared to maintain current supply at this level to maintain share in the long term. If it stopped short of its intended goal of slowing US supply, why embark on this path in the first place? Lastly we consider the possibility geopolitically -related and other production decreases or increases. Libya comes to mind first as recent unrest shutdown its El Sharara field, which was producing 270K b/d. This decreased November production down to 638K b/d from its previous peak of 883K b/d. As lower oil prices continue to pressure Venezuela and its stability, that will be another country to watch. Rounding out the areas of interest are West African deepwater projects and Russian Arctic projects - both of which are on the high-end of the breakeven cost spectrum. Beyond these specific areas to watch, we would point out Non-OPEC related growth does tend to underwhelm, and it would need to outperform on a larger scale in 2015 to offer any meaningful upside surprise large enough to affect oil prices. The last wild card we would point out here is China and its Strategic Petroleum Reserve (SPR). China's SPR purchases averaged —500K b/d for most of 2014. Now, Chinese SPR-related imports are thought to have peaked in December as the country took advantage of depressed oil prices with upwards of 700K b/d in estimated purchases. Despite brisk Chinese demand last month, most expect this specific demand level to moderate moving forward as the country is apparently close to filling existing reserve capacity. The combination of all of the previous five factors, seasonality in particular, is clearly reflected in investors current thinking on oil prices. DB recently surveyed equity investors with a majority of those surveyed (70%) of the belief that oil will bottom by the end of 1H 15. In particular, that same set of investors overwhelmingly believes that North American crude supply is the biggest driver of oil prices (50% ranked it the top factor). We would tend to agree more with the second observation and believe that the signs of slowing North American production are key to the recovery in oil prices after 1H 15 seasonality plays through; we believe improving oil price will require some positive oil supply data points (e.g. inventory draws coming in 2H 15, continued progress on decreasing horizontal rigs in the Big Three oil plays) to give that psychological boost needed to change oil market momentum, even if those positive data points don't immediately translate to lower observed supply growth. In the near term (1 H 15), we would expect to see sub-$50 oil persist as the market continues to be oversupplied by1.4 million b/d. Also, to put current trading levels into perspective, WTI prices would need to fall to $45 to surpass the 58% collapse in the oil price during the Jan 97/Dec 98 episode; it seems appropriate to compare recent price action to that episode since during the first half of this year global oil supply will be growing in excess of global oil demand by its largest margin since 1998. Specifically, we think this 97/98 case also speaks to the possibility of 2015 being a lost year, and thus, investors focus on 2016 as the next meaningful point in time for price recovery. Given we are approaching what could be the lows in oil, where we with HY E&P in the credit cycle now? While we have seen many episodes where oil prices have declined over 50%, none of those were prolonged enough to coincide with a restructuring of the entire E&P sector during a time when we had a fully developed and functioning HY market. For example, the 1986 episode did illustrate a Page 10 Deutsche Bank Securities Inc. EFTA01097664 13 January 2015 HY Corporate Credit Energy prolonged bear market in oil, but there is no reliable data for that period. What this table and particular analysis shows us is that we are at and beyond the average decline for an oil cycle, which is a 50% decline. That said, while finding the bottom for oil is important, the recovery story is equally important. IFigure 10: Cumulative cyclical peak default rates in HY and IRRs on energy bonds from current levels Year 1 Year 2 Year 3 Coupon Price To: Year 1 Year 2 Year 3 Cyclical Peak Cumulative Default Rates Surviving Par BBB 0.5 1.1 1.8 5.5 106.0 BBB 100 100 99 99 BB 1.7 6.6 10.1 6.0 95.8 13B 100 99 96 94 B 5.7 18.2 25.1 7.4 81.9 8 100 97 91 87 CCC 19.9 42.3 51.6 8.4 59.2 CCC 100 94 86 83 All HI 5.7 16.7 22.9 6.8 85.5 HY 100 97 91 88 Single-Bs/CCCs 32.4 Coupon BBB 5.5 5.5 5.4 BB 5.9 5.8 5.7 8 7.3 6.9 6.6 CCC 8.1 7.6 7.1 HY 6.7 6.4 6.1 Percent Downgraded BBB 20 10 5 BB 25 13 6 8 .- _ _ CCC — Dollar Prices, Adjusted for Downgrades BBB 106 102 101 100 BB 96 89 87 86 a 82 82 82 82 CCC 59 59 59 59 HY 86 82 81 81 Market Value (Credit Loss . Coupon 4 Downgrades) IRR BBB 106 107 106 105 -1.2 BB 96 94 90 87 -9.4 B 82 87 81 78 -4.8 CCC 59 64 59 56 -4.7 HY 86 87 82 79 -7.3 Sousa °anent Ban*Ove4 arraroev While we don't have a specific example of an energy sector restructuring, our counterparts in credit strategy have done work on cumulative cycle peak default rates in the overall HY sector. In Figure 10. they show average cumulative default rates in HY over the last three credit cycles (measured in 1989-1991, 2000.2002, and 2008-2010 by Moody's issuer-weighted rates). According to this data, we are looking at an average cumulative default rate of 22.9% for the whole HY spectrum and 51.6% for CCCs only. Looking at the bottom section, titled Market Value, $59 invested in an average CCC energy bond today should return $56 at the end of year 3 yielding a -4.7% IRR. Percent changes on the right are calculated between these two values, non- annualized. So how do we interpret these numbers? The good news here is that using a relatively negative set of assumptions — cyclical peak default and downgrade rates (based on broad market historical stets) and unchanged dollar prices on the exit from year three — are resulting in only single-digit negative retums from here, implying that to a good extent, the bad news has been priced in. An important bullish assumption that we are purposefully not including here - that a surviving CCC could be worth more than $59 at the end Deutsche Bank Securities Inc. Page 11 EFTA01097665 13 January 2015 HY Corporate Credit Energy of year 3 - could single-handedly result in positive IRRs. Consider: only three months after the end previous two credit cycles in 2002 and 2009, an average CCC jumped in price from low 50-ies to low 70-ies (measured in June 2003 and June 2009). If we were to plug in a $70 year 3 price assumption for surviving CCCs in Figure 10, non-annualized IRR jumps to +10%. For a more detailed explanation of assumptions to reach these conclusions, please see DB's US Credit Strategy: What is Priced in Energy Bonds Here? (December 18, 2014). Despite a dearth of examples around a crisis in HY energy, or more specifically the E&P sub-sector, we do have some examples of where other distressed HY sectors traded at crisis levels (right). If these restructured sectors hold any weight, it seems by this metric, we still have downside on a spread-basis before we reach the bottom for HY E&P bonds. Despite somewhat conflicting answers from the above two analyses, we think the takeaway for HY credit is that we are getting there but not be at the optimal entry point for bonds. Further, investors need to consider time horizons as they relate to various investing strategies and whether or not funds are locked-in. Lastly, with a significant level of default (blended rate of 30% for B/CCC), there will be clear winners and losers, outcomes will be very binary outside of buying a diversified basket of lower-quality HY E&P credits. Figure 11: Widest Levels of Each Crisis 88s 8s CCCs Real Estate 12/31/2008 1,573 2,008 4,702 Media 11/30/2008 1,128 2,029 3,508 Autos 12/31/2008 1,546 2,036 2,473 Telecoms 07/31/2002 1,398 1.014 3,966 Gaming 11/30/2008 1,895 1,870 2,485 Average 1,508 1,791 3,427 Energy 01/08/2015 465 960 1,896 % of other crisis levels 30.9%53.6% 55.3% What can we expect in terms default rates and recovery should there be a full- Sane Dooncft Bent scale restructuring of energy names? As we have not seen a full scale restructuring of the sector is hard to pinpoint exact figures here. Moodys reported that during the last two credit cycles for E&Ps (1998-1999, 2001-2002), a majority of unsecured creditors received a range of 35-50% recoveries with an average recovery of 40%. This is better than the average industrial recovery of 29%. Fitch has reported similar numbers. From 2000-2013, the average recovery rate for energy was 45%; compared to a 37% for the total market. However, the spread on recoveries in any given year was relatively wide with a low of 8% in 2001 and a high of 76% in 2011 looking at the Fitch data. Important to note that per Fitch, the comparative default rates for energy have been relatively mild at 2.0% from 1980-2012, this compares to a 4.6% default rate for the overall market during the same period. What other major catalysts need to play out to trigger defaults for HY E&Ps? As we look at maturities due in HY energy over the next couple of years (Figure 12), it is clear that most energy companies including E&Ps have termed out debt. This is not surprising given the historically low rates issuers have achieved in the HY market over the last several years. One can see that there is a little less than $4 billion in overall energy HY bonds coming due in the next two years. In Figure 13, we lay out the specific energy bonds that are coming due in 2015 and 2016. After those years, we see a relatively larger maturity wall of $18 billion in 2017. Page 12 Deutsche Bank Securities Inc. EFTA01097666 2015 2016 13 January 2015 HY Corporate Credit Energy 'Figure 12: North American HY Energy Debt Maturities Ex-Coal 32 38 45 44 22 2025. 2017 2,018 2019 2020 2021 2022 2023 2024 23 Sew& r Deundie &Mk Itibarktep Ramo. LA •BB ■B •CCC Total 'Figure 13: Specific 2015/2016 Debt Maturities Issuer Ticker Maturity Notional Currency Country Energy Sub-Sector Moodys S&P 'SIN Vermillion Energy VETCN 2016-02-10 $199 CAD CA Oil Comp-Explor&Prodtn NR 8B-CA923725AA31 Black Elk Energy BLELK 2015-12-01 $139 USD US Oil Comp-Explor&Prodtn NR B-US09203YAC57 Boardwalk Pipelines LP BWP 2016-11-15 $250 USD US Pipelines/Energy Storage 8aa3 BB+ US096630AA61 Chesapeake Energy CHK 2016-03-15 $500 USD US Nat Gas Exploration Bat BB+ US165167C.149 OEP Resources OEP 2016-09.01 $177 USD US Nat Gas Exploration Bat BB+ US74836JAD54 Quicksilver Resources KWK 2016-04-01 $350 USD US Nat Gas Exploration Ca C US74837RAC88 RAAM Global Energy RAMGEN 2015-10.01 $243 USD US Oil Comp-Explor&Prochn Caa3 CCC+ US74920AAC36 Rockies Express Pipeline ROCKIE 2015-04-15 $450 USD US Pipelines/Energy Storage Ba2 BB US77340RAH03 Sabine Pass LNG LP COP 2016-11-30 gun USD US Pipelines/Energy Storage 81 8B+ US785583AF20 $3,790 SOW* Z1/4•01010 &ink COnvhgew DMA We really see further default triggers coming down to borrowing base redeterminations. While ostensibly there is not a significant amount of debt coming due in the next two years, what simply looking at the maturity schedule misses is the way HY issuers have traditionally used their reserve based lending facilities ("RBIs"). In a nut shell, E&Ps, especially those with lower credit ratings, use these facilities as a way to fund near term drilling plans with intention of terming out these draw downs with HY bonds. Looking at Figure 14, many E&P currently have 50% or more availability on their revolvers. Looking forward two years in different oil price scenarios ($50/$60/$70 oil & $3.75 nat gas) and assuming some increases in borrowing bases as E&Ps increase PV-10, then about 15.35% of high yield E&P issuers in the broad universe we are screening have less than 50% RBL availability at FYE 16. Looking at a more conservative case, where the screened universe is afforded no borrowing base increases, then more like 20.50% of HY issuers have less than 50% RBL availability at FYE 16. Looking more closely at the figures, there are certain issuers that would actually have negative availability. In other words, they would need to raise more capital in addition to their current borrowing base as the scenario analysis shows these companies running out of cash. Further, there is a possibility that banks do in fact decrease the borrowing base of some of these E&P causing an even more draconian scenario. Deutsche Bank Securities Inc. Page 13 EFTA01097667 13 'Figure 14: HY E&P Liquidity Overview as $ milions Trek& Company Name Borrowing Base Commitment Resulting Avallablity % Available All Current as of Availability (2) 9/30/14 (2) RBL (Overdrawn)/Available in 2 years as %of starting Availability Selective Borrowing Base Increases (3) m P. RBL (Overdrawn)/Available in 2 years as %of starting Availability Borrowing Base Unchanged (31 9. 2 "8 N O$70/$3.75 at FYE 16 560/53.75 at FYE 16 $50/53.75 at NE 16 570/53.75 560/53.75 at FYE 16 at EYE 16 $50/53.75 at EYE 16 ALM American Permian Caal/CCC, $650 $1.000 $650 $550 85% -5% -21% -36% -54% -77% 100% C. MPO Midstates Petroleum 9.(Stable)/Caal(Stable) $525 $750 $525 $154 29% 18% 16% .6% -71% -113% -195% son/sr Samson Investment Caal(Neg W)/CCC(Neg W) $1,000 $2,250 $1,000 $411 41% 21% 10% -1% -70% -95% -119% SEVGEN Seven Generations 931 Pos)/CCC.(Stable) $480 $480 $480 $480 100% 15% 20% 5% -36% .66% -97% WPX WPX Energy 9a1(Stab!e)/EtB4(Negi NA $1,500 $1,500 $614 41% 77% 37% 19% 70% 24% 2% MHR Magnum Hunter 93iStable)/CCCINeg) $325 $750 $325 $175 54% 43% 33% 24% -49% -73% -99% HIE HiIcor is Energy Ela3 MEW $1,400 $1,250 $1,250 $1,249 100% 63% 44% 26% 58% 38% 17% 50 SandRidge Energy 92iStable)/B.IStablel $1,200 $900 $900 $746 81% 63% 46% 29% 42% 15% -12% ROSE Rosetta Resources 91iStable)/681Stablel $950 $800 $800 $690 86% 94% 73% 51% 91% 69% 46% XEC Cimarex Energy 9a l(Positive)/BEW(Positive) $2,500 $1,000 $1,000 $998 100% 122% 89% 55% 124% 87% 51% CXO Concho Resources 843(Ros)/BEW(Stable) $3,250 $2,500 $2,500 $2,500 100% 71% 64% 57% 65% 57% 48% SM SM Energy 9a2(Stable)/BEI(Pos) $2,400 $1,500 $1,500 $1,499 100% 84% 71% 58% 71% 50% 27% RRC Range Resources ElaT(Ros)/18 4(Stable) $3,000 $2,000 $2,000 $1,247 62% 86% 73% 60% 81% 67% 52% PVA Penn Virginia Caal(Stabk)/6-(Stabk) $438 5450 $438 $498 114% 81% 72% 64% 75% 63% 52% XCO EXCO Resources 93iStable)/CCC.(Stable) $900 NA $900 $789 88% 71% 68% 64% 66% 62% 58% BCE I Bonann Creek Energy 93iStable)/B.IStablel $450 $400 $400 5426 107% 109% 88% 65% 111% 85% 57% AR Antero Resources 91istab!e)/EtEt (stable) $4,000 $1.060 $3,000 $2,506 84% 85% 76% 68% 79% 67% 55% TPLM Triangle Petroleum Caal/CCC, $415 $500 $415 $430 104% 79% 76% 71% 60% 54% 49% PE Parsely Caal/CCC4(Stabk) $328 $750 $328 $327 100% 109% 97% 77% 111% 96% 72% TLW Tullow Oil 92/B. NA $4,750 54,750 $2,300 48% 92% 85% 78% 92% 85% 78% FANG Diamondback Energy 93i Pos)/B.(Pos) $350 5600 $150 $320 91% 127% 103% 80% 145% 106% 66% LTSCN Lightstream Resources Caa2( Neg)/CCOiNeg) NA $1,150 $1,150 5606 51% 121% 103% 85% 121% 103% 85% OAS Oasis Petroleum 92iStable)/EHStabkl $2,000 $1,500 $1,500 $1,145 76% 112% 101% 90% 114% 102% 89% ONR Denbury Resources 91iStable)/98 (Stable) $1,600 $1,600 $1,600 $1,178 74% 142% 120% 91% 142% 120% 93% EPE EP Energy 92/Et $2,500 $2,500 $2,500 $1,849 74% 99% 97% 95% 99% 95% 92% HIE Halton Resources Caa1(Stabk)/CCC.IStable) $1,050 $1,500 $1,050 $704 67% 108% 102% 97% 111% 104% 95% HOC Newfield Exploration 9a1(Stabk)/BEW.(Stable) NA $1,400 $1,400 $1,377 98% 126% 127% 99% 126% 127% 99% SN Sanchez Energy 93i Pos)/9-(Pos) $650 $300 $300 $300 100% 169% 147% 126% 238% 195% 151% QEP QEP Resources 9a1(Stabk)/BB4(Stable) NA $1,800 $1,800 $1,796 100% 161% 146% 131% 161% 146% 131% CHIC Chesapeake Energy gal (Positive)/684 (Positive) $4,000 $4,000 $4,000 $1,937 98% 188% 162% 137% 188% 162% 137% F 5 8 F son Deanne Bonk 01 Airetwo'n on*ratketelioudivn th: $6049 7.5coe, save there o no mime as me &atom., bra, thrown 2014 !?I MoVoVe wore Rees an 0 any edStonslisoWer OAR wow', A ii evatbl• "mar FEY woe penned alum me 21“, Damn' AScreenmaw ItY wet ~clomp NA, 2.µwrenack 099,41** Aottworvibokrov con bulb pone. men 100% eyeAWwyN 9/ pero0 EFTA01097668 13 January 2015 HY Corporate Credit Energy In the past what has caused the banks to decrease RBLs for HY issuers? Overall, since the mid-1990s (start of reliable data), lenders have seen par recovery on RBL facilities in all distressed and bankruptcy situations according to S&P. There are two main reason why this is the case. First, reserve engineers at the major lending banks use a lower price deck than the actual commodity strip price as a base case. And beyond that, the banks run a further sensitivity (aka downside case) that they generally rely on to give them confidence during commodity market dislocations like this one. The second reason banks haven't taken losses on these RBLs is that internal reserve engineers also take a additional discount to the already discounted (9-10%) expected cash flows coming from an E&P's proved reserves. Generally, Proved Developed Producing reserve are discounted at 25%; Proved Developed Non-Producing are discounted at 50%; Proved Undeveloped (PUDs) are discounted at 75%. This is in addition to subtracting out the expected cash flow for the next 6 months of planned production out of the RBL borrowing base. This borrowing base calculation does however give producers the benefit of hedges. Given a lack of material losses in the types of products banks are generally reluctant to materially reduce the RBLs of E&P especially during dislocations like the one we are seeing in oil right now. The general philosophy of the lending banks has been to be more conservative in both directions. When commodities (oil, nat gas) are rallying, banks are slow to move the price deck up; however, the same is true on the way down, which benefits E&Ps in today's bear oil market. That said, borrowing bases were reduced in 08/09, although these reductions were very minor compared to the over 70% decline in oil prices. There have been situations where the banks will reduce borrowing bases more meaningfully. This can happen when an E&P with an already weak financial profile enters a bear commodity market, or an E&P experiences a sudden change in its reserves or production profile (dramatic and unexpected cost increase, reserve write downs, unexpected decline in current production). Can E&Ps raise more money in the HY market today? If necessary BB-rated E&Ps can come to market to issue given average spreads in the 450.470 bps range; looking at our previous liquidity overview, one can see that most of these E&P are in good shape and don't need to issue. Moving down the credit spectrum, lower-rated single-B and triple-C companies are the ones more likely to need the capital. Given that the spreads for energy single-B and triple-C companies are currently 950-970bps and 1,880.1,900bps, respectively, we don't see more traditional unsecured HY deals as feasible today. This highlights the cost of capital problem that lower rated E&P companies now face - these are the real "have nots" in our minds. With traditional HY avenues not open to them we believe two trends will emerge. First, we will see more bilateral deals between E&Ps and providers of capital (private equity, recently-launched energy funds, special situations funds). We have already seen one recent example of this between Linn Energy (LINE) and GSO/ Blackstone (BX). LINE now has a five- year $500 million agreement whereby GSO will earn up to a 15% RoR on wells drilled by LINE in exchange for providing 100% of the upfront drilling costs. EXCO Resources (XCO) led the way on transactions like this; it struck a similar agreement with KKR & Co (KKR) in July 2013 in the Eagle Ford. Rightly so, we believe investors would rather invest in a company and make survival a self fulfilling prophecy rather than try to build sizable positions through the secondary market where ownership brings no incremental certainty around survival. The second trend will be second lien deals. E&P bond indentures are written with relatively open language around the way credit facilities are defined and the Deutsche Bank Securities Inc. Page 15 EFTA01097669 13 January 2015 HY Corporate Credit Energy around liens incurred under debt incurrence tests. We have not seen anything on this front yet, but it's only a matter of time especially with RBLs more likely to shrink in size. This is a clear negative for unsecured debt due to layering. The longer the bear oil market lasts, the more likely second lien deals will come. Will defaults help us move the overall market closer to equilibrium? Unfortunately, we believe many HY E&P companies, particularly single-B and triple-C credits, will be collateral damage rather than contributing meaningfully towards balancing global crude markets. Our equity counterparts have stress tested 2015 US supply growth; the results show that nearly 85% of crude supply growth remains manageable as those producers will remain under 2.5x net debt to EBITDA at FYE 2015 at $70/bbl WTI and $3.75/mcf gas (below). While we are well below that crude price now, it is important to note that about 50% of the 2015 US crude volumes are hedged. This ratio will decline in 2016, but the bottom line is that the larger, more highly-rated producers need to slow production in order to start to see changes to global balances - not the smaller HY players. Figure 15: Funding constraints will eventually have a material impact on supply growth, but nearly 85% of crude supply growth remains manageable at $70/bbl crude through the end of 2015 60 50 .O 40 - t Got 30 >- 0 DO 20 OO000000 O OD -111- 1 1 0 fAetteetp-olat tleetel-ettettladq-i 9k9W0-0 Saeca. Deutsche Sant CmgnySw'135% of 2015 US oil growth comes from companies with less than 2.5x YE2015 Net Debt/EBITDA at $70/bbl, $3.75/mcf 00 O O • 2015 Oil Growth *2015 Net Debt/EBITDA 5.0 4.5 4.0 3.5 7..6 3.0 o 2.5 co 2.0 A 1.5 1.0 .; 0.5 0.0 What is the market currently pricing in for HY energy bonds? Given this, when should investors look to take positions in HY energy bonds? The preceding indicates that where HY and energy are concerned, we are in uncharted territory. As we mentioned before, there is no good set of energy- specific data to get an idea of an exact entry point for investors. Despite signals of being close to the bottom, there is little clarity on whether this is a "U" or "V shaped commodity (and there HY bond) recovery, which will make a significant difference in how investors with different strategies and timelines look to enter trades. Even if we had seen a significant set of restructurings in HY before, there can be vastly different triggers for those restructurings. Most likely, we see (i) weak balance sheets upon entry into the crisis, (ii) reduced liquidity, and (iii) concentrations in relatively higher cost plays as being the biggest driver of defaults in B/CCC credits -which we believe will be a more clear signal of the eventual entry point. Page 16 Deutsche Bank Securities Inc. EFTA01097670 13 January 2015 HY Corporate Credit Energy Then, who is best positioned to withstand this downturn should it be a three- year cycle? In the HY credit markets, liquidity will be a top driver of performance combined with assets in the best marginal costs plays. This will be further enhanced by better clarity of through cycle leverage. Companies starting off with reasonable leverage, moderate FCF burn, and good hedging are already ahead of the game. In addition, companies that recently termed out RBLs and are working with a high % of current availability will also be well positioned. Lastly, E&Ps that were able to execute on asset sales at pre-crisis valuations are also positioned well where liquidity is concerned. Some HY companies trying to see assets will see those plans put on hold, while others who recently bought will now look like they overpaid. If we want to invest in HY E&P today, how do we sift through the more fragment E&P credits to identify outliers? To answer this question, we developed a screen to apply across a universe of approximately 30 high yield credits - some of which we have a rating on (ie covered companies) and some of which we do not. In order to include non- covered companies in this analysis, we have used Bloomberg consensus estimates to develop sensitivity analysis. Please see the following section called "E&P Universe Screening Methodology" for the full details on our methodology for screening the HY E&P universe and creating sensitivity analysis across all 30 credits. Deutsche Bank Securities Inc. Page 17 EFTA01097671 13 January 2015 HY Corporate Credit Energy E&P Credit Screens and Analysis E&P Credit & Operational Metric Screen When looking at trying to help investors wade through the extremely fragmented E&P sector in US HY, we looked across six main credit and operational metrics including 2016 net leverage, current PV-10 to 2016 net debt, 2016 liquidity assuming a flat borrowing base, 2015 hedges, 2016 adjusted cash margin per unit, and 2016 production mix. We felt this range of metrics would give a wide and varied insight into the path that certain E&Ps might take over the medium term commodity cycle (three years). We first